natural gas pipeline new mexico us

Pipeline Accident Report

Natural Gas Pipeline Rupture and FireNear Carlsbad, New MexicoAugust 19, 2000

National Transportation Safety BoardWashington, D.C.

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NTSB/PAR-03/01PB2003-916501

Pipeline Accident Report

Natural Gas Pipeline Rupture and FireNear Carlsbad, New MexicoAugust 19, 2000

NTSB/PAR-03/01PB2003-916501 National Transportation Safety BoardNotation 7310B 490 L�Enfant Plaza, S.W.Adopted February 11, 2003 Washington, D.C. 20594

National Transportation Safety Board. 2003. Natural Gas Pipeline Rupture and Fire Near Carlsbad,New Mexico, August 19, 2000. Pipeline Accident Report NTSB/PAR-03/01. Washington, D.C.

Abstract: At 5:26 a.m., mountain daylight time, on Saturday, August 19, 2000, a 30-inch-diameter naturalgas transmission pipeline operated by El Paso Natural Gas Company ruptured adjacent to the Pecos Rivernear Carlsbad, New Mexico. The released gas ignited and burned for 55 minutes. Twelve persons whowere camping under a concrete-decked steel bridge that supported the pipeline across the river were killedand their three vehicles destroyed. Two nearby steel suspension bridges for gas pipelines crossing the riverwere extensively damaged. According to El Paso Natural Gas Company, property and other damages orlosses totaled $998,296.

The major safety issues identified in this investigation are the design and construction of the pipeline, theadequacy of El Paso Natural Gas Company�s internal corrosion control program, the adequacy of Federalsafety regulations for natural gas pipelines, and the adequacy of Federal oversight of the pipeline operator.

As a result of its investigation of this accident, the National Transportation Safety Board makes safetyrecommendations to the Research and Special Programs Administration and NACE International.

The National Transportation Safety Board is an independent Federal agency dedicated to promoting aviation, railroad, highway, marine,pipeline, and hazardous materials safety. Established in 1967, the agency is mandated by Congress through the Independent Safety BoardAct of 1974 to investigate transportation accidents, determine the probable causes of the accidents, issue safety recommendations, studytransportation safety issues, and evaluate the safety effectiveness of government agencies involved in transportation. The Safety Boardmakes public its actions and decisions through accident reports, safety studies, special investigation reports, safety recommendations, andstatistical reviews.

Recent publications are available in their entirety on the Web at <http://www.ntsb.gov>. Other information about available publications alsomay be obtained from the Web site or by contacting:

National Transportation Safety BoardPublic Inquiries Section, RE-51490 L�Enfant Plaza, S.W.Washington, D.C. 20594(800) 877-6799 or (202) 314-6551

Safety Board publications may be purchased, by individual copy or by subscription, from the National Technical Information Service. Topurchase this publication, order report number PB2003-916501 from:

National Technical Information Service5285 Port Royal RoadSpringfield, Virginia 22161(800) 553-6847 or (703) 605-6000

The Independent Safety Board Act, as codified at 49 U.S.C. Section 1154(b), precludes the admission into evidence or use of Board reportsrelated to an incident or accident in a civil action for damages resulting from a matter mentioned in the report.

iii Pipeline Accident Report

Contents

Executive Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . v

Factual Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1Accident Synopsis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1Accident Narrative . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1Emergency Response . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7Pipeline Operations After the Rupture . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10Postaccident On-Site Inspection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10Injuries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11Damages . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12Toxicological Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12Tests and Research . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

Metallurgical Examination . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13Corrosion Products . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

Pipeline 1103 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16Pipeline Features . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16Gas Suppliers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17Pigging Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18Tests and Inspections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

EPNG�s Internal Corrosion Program . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21Internal Corrosion Control Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23Internal Audit Program . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

Regulatory Oversight . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26Federal Safety Standards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26Preaccident Federal Inspections of EPNG . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28Federal Safety Standards and EnforcementæMaps and Records . . . . . . . . . . . . . . . . . 29

Postaccident Actions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30Pipeline Reconstruction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30Pipeline Integrity Management . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31Federal Response . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

Pipeline Integrity ManagementæFederal Regulations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33NACE Standards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35ASME Code for Gas Piping (B31.8) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35Guide for Gas Transmission and Distribution Piping Systems . . . . . . . . . . . . . . . . . . . . . . 36Other Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36

Previous EPNG Internal Corrosion Accident . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36Emergency Training and Simulations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37

Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38Exclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38Emergency Response . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39Internal Corrosion in Steel Gas Pipelines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39Internal Corrosion in Line 1103 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40Physical Features of Line 1103 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41EPNG Internal Corrosion Control Program . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43

Contents iv Pipeline Accident Report

Federal Safety Regulations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46Federal Oversight of the Pipeline Operator . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46Industry Standards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48

Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49Findings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49Probable Cause . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50

Recommendations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51

AppendixesA: Investigation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53B: Summary of Office of Pipeline Safety Corrective Action Order . . . . . . . . . . . . . . . . . . 54C: Research and Special Programs Administration Advisory Bulletin . . . . . . . . . . . . . . . . 56

v Pipeline Accident Report

Executive Summary

At 5:26 a.m., mountain daylight time, on Saturday, August 19, 2000, a 30-inch-diameter natural gas transmission pipeline operated by El Paso Natural Gas Companyruptured adjacent to the Pecos River near Carlsbad, New Mexico. The released gas ignitedand burned for 55 minutes. Twelve persons who were camping under a concrete-deckedsteel bridge that supported the pipeline across the river were killed and their three vehiclesdestroyed. Two nearby steel suspension bridges for gas pipelines crossing the river wereextensively damaged. According to El Paso Natural Gas Company, property and otherdamages or losses totaled $998,296.

The National Transportation Safety Board determines that the probable cause ofthe August 19, 2000, natural gas pipeline rupture and subsequent fire near Carlsbad, NewMexico, was a significant reduction in pipe wall thickness due to severe internalcorrosion. The severe corrosion had occurred because El Paso Natural Gas Company�scorrosion control program failed to prevent, detect, or control internal corrosion within thecompany�s pipeline. Contributing to the accident were ineffective Federal preaccidentinspections of El Paso Natural Gas Company that did not identify deficiencies in thecompany�s internal corrosion control program.

The major safety issues identified in this investigation are as follows:

� The design and construction of the pipeline,

� The adequacy of El Paso Natural Gas Company�s internal corrosion controlprogram,

� The adequacy of Federal safety regulations for natural gas pipelines, and

� The adequacy of Federal oversight of the pipeline operator.

As a result of its investigation of this accident, the National Transportation SafetyBoard makes safety recommendations to the Research and Special ProgramsAdministration and NACE International.

1 Pipeline Accident Report

Factual Information

Accident Synopsis

At 5:26 a.m., mountain daylight time, on Saturday, August 19, 2000, a 30-inch-diameter natural gas transmission pipeline operated by El Paso Natural Gas Company(EPNG) ruptured adjacent to the Pecos River near Carlsbad, New Mexico. The releasedgas ignited and burned for 55 minutes. Twelve persons who were camping under aconcrete-decked steel bridge that supported the pipeline across the river were killed andtheir three vehicles destroyed. Two nearby steel suspension bridges for gas pipelinescrossing the river were extensively damaged. According to EPNG, property and otherdamages or losses totaled $998,296.

Accident Narrative

The EPNG pipeline system (figure 1) transported gas west from Texas and NewMexico to Arizona and California. A portion of the pipeline system crossed the PecosRiver about 4 1/2 miles north of the Texas-New Mexico State line and 30 miles south ofCarlsbad, New Mexico. (See figure 2.) About 1 mile west of the river crossing was thePecos River compressor station, which received gas from four natural gas transmissionpipelines26-inch-diameter line 1100, 30-inch-diameter line 1103, 30-inch-diameter line1110, and 16-inch-diameter line 3191. Three of these lines (1100, 1103, and 1110) ranparallel to Whitethorn Road (also known as Pipeline Road) from the Pecos River to thePecos River compressor station. Lines 1103 and 1110 were supported at the river crossingby a one-lane concrete-decked steel service bridge that was not open to the public. (Seefigure 3.) (This bridge, which had been built by EPNG in 1950, also supported a waterpipeline and a gas gathering pipeline. EPNG, which was at the time of the accident asubsidiary of El Paso Energy, owned and operated the water pipeline but not the gasgathering pipeline.) Line 1100 was supported across the river on a pipeline suspensionbridge approximately 70 feet northeast of the service bridge. Another EPNG pipeline, 16-inch-diameter line 1000, was supported by a separate suspension bridge in this area, butthis line had been removed from service and was filled with nitrogen at the time of theaccident. The fourth pipeline, line 3191, ran from EPNG�s South Carlsbad compressorstation to the Pecos River compressor station.

Factual Information 2 Pipeline Accident Report

Figure 1. El Paso Natural Gas system.

Figure 2. Accident area.


At the time of the accident, 12 members of an extended family were camping onthe east bank of the Pecos River near the service bridge.1 (See figure 4.) A locked wirerope and a �Private Right of WayNo Trespassing� sign at each entrance to the bridgerestricted access to the bridge above the campsite. Two �CautionHigh Pressure GasLine� signs were posted near the east entrance to the service bridge. Also, a sign readingas follows:

Warning - No Trespassing - This road and right of way is private property and isnot for public use. This pipeline carries natural gas under high pressure and isdangerous. All persons are warned of the danger to person and property. KEEPOFF

had been posted alongside the right-of-way road (near the intersection with the countyroad) leading past the block valves and pig receivers to the service bridge on the east sideof the river.The pipeline system was operated from EPNG�s gas control center in El Paso,Texas, as a north system and a south system. The gas control center was equipped withthree supervisory control and data acquisition (SCADA)2 system work consoles, each ofwhich was capable of displaying data for both pipeline systems.

On the morning of August 19, 2000, three EPNG employees, a coordinator ofpipeline control (who was in charge of the shift) and two gas controllers, were nearing the

Figure 3. Accident site.

1 At the time of the accident, a private landowner owned the accident site. After the accident, EPNGpurchased this property and installed fencing to restrict access to the area.

2 Pipeline controllers use a computer-based SCADA system to remotely monitor and controlmovement of gas through pipelines. The system makes it possible to monitor operating parameters critical topipeline operations, such as flow rates, pressures, equipment status, control valve positions, and alarmsindicating abnormal conditions.


end of their 12-hour shifts at the gas control center. One of the controllers was operatingthe north system and the other the south, while the coordinator assisted the two controllersand performed administrative oversight and served as a backup controller when needed.The two controllers were working at separate SCADA terminals to monitor and controlpipeline operations. The employees said they had noted no unusual operating conditionsduring their shift, and no unusual conditions had been noted during the previous 12-hourshift.

The south system controller, at 5:26 a.m.,3 received SCADA rate-of-change4

alarms for the speed of compressor unit No. 3 at the Pecos River compressor station.5 Lessthan a minute later, compressor unit No. 1 at the station shut down, quickly followed bythe automatic closing and opening of station valves, as appropriate, to isolate thecompressor station from the pipeline. Emergency lubricating oil pumps were alsoautomatically activated at the station. A few seconds later, additional alarms from thestation displayed on the controller�s monitor, including a rate-of-change alarm for falling

Figure 4. Aerial view of accident site looking east.

3 Times in this section are based on SCADA event data recorder records, controller logs, and personnelstatements and interviews.

4 Rate-of-change alarms indicate that a measured variable, such as compressor speed or compressorsuction pressure, is increasing or decreasing at a rate exceeding what would be expected under normaloperating conditions.

5 The unattended Pecos River compressor station had three turbine compressors.


suction (inlet) pressure at the station. (Unknown to the controller at the time, pressure onthe inlet side of the station dropped because pipeline 1103 had ruptured near the rivercrossing.) Noting the alarms, the south controller began to request SCADA data for thePecos River compressor station instead of waiting for the data to appear from theautomatic data scans, which occurred at 4-minute intervals.6

At about this time, the transmission of SCADA data between the gas control centerand the Pecos River compressor station was briefly interrupted. According to the southcontroller, he was immediately alerted to the data interruption by the display of inversevideo on his SCADA monitor. Inverse video indicated that a proper reply to a request fordata from the SCADA system had not been received and that the displayed data were notbeing updated. Although not recorded in the SCADA system event log, this interruptionlasted about 30 seconds.

At approximately 5:30 a.m., the controller telephoned the Pecos River districtstation lead operations specialist7 at home and asked him to send people to the Pecos Rivercompressor station. The south controller later stated:

I noted that we did have a low suction pressure, and generally when our plants godown, the suction pressure goes up instead of down. I told [the station leadoperations specialist], �We need to get somebody out there right away because Ithink we have a problem.�

The station lead operations specialist called two operations specialists that hesupervised and who were on duty and told them to go to the Pecos River compressorstation.

About the same time the station lead operations specialist was making this call, anEPNG operations specialist from the Carlsbad complex, who was at his home south of thecity of Carlsbad, noticed a glow in the sky to the south. (See figure 5.) He said heimmediately suspected that an EPNG pipeline may be involved. He called the gas controlcenter and asked if its personnel had noticed any sudden pressure changes at the PecosRiver compressor station. He told center personnel of the glow in the sky and said that hesuspected a rupture. The north controller informed him that EPNG had lost a compressorat the Pecos River compressor station.

The operations specialist then telephoned his supervisor (the pipeline leadoperations specialist), and informed him of the glow in the sky and of his call to the gascontrol center. He then told the pipeline lead operations specialist that he was on his wayto the Pecos River compressor station.

6 This SCADA system logged operational data and transferred it to the gas control center via modem.7 EPNG had two employees in the Pecos River district with the official title �lead operations

specialist.� One lead operations specialist supervised operations specialists responsible for operating andmaintaining compressor and meter stations. Another lead operations specialist supervised operationsspecialists responsible for operating and maintaining pipelines. This report refers to the two employees,respectively, as the station lead operations specialist and the pipeline lead operations specialist.


At 5:31 a.m., the gas control center in El Paso again experienced an interruption inSCADA data transmission from the Pecos River compressor station, which prevented thecontroller�s receiving any additional information from the station. The interruptionoccurred when the emergency shutdown system at the Pecos River compressor stationactivated, which caused a loss of power to the local SCADA computer and modem. Thestation was equipped with an uninterruptible power supply, but the station SCADAcomputer and modem were not connected to it.8 SCADA communications with the PecosRiver compressor station were restored at 9:04 a.m. on August 19.

At 5:35 a.m., the south controller again telephoned the station lead operationsspecialist at home and told him that he suspected a possible line blowout. At this time, thesouth controller did not know which pipeline was involved. The station lead operationsspecialist said that after looking out a window of his home in the direction of the PecosRiver compressor station, he told the south controller that he could see a fire and that hewas on his way to the Pecos River compressor station.

Figure 5. Post-rupture fire. At lower left of fireball can be seen the 85-foot-tall support structures for the pipeline suspension bridges.

8 The station was equipped with an uninterruptible power supply to maintain AC power to the stationcomputer and hazardous gas and fire detection equipment. A 24-volt DC backup system maintained powerto oil pumps, nozzle cooling water equipment, and other emergency equipment in the event of a stationpower failure.


At 5:44 a.m., the south controller called the Keystone compressor station9 andasked the operator to take down three compressor units. About a minute later, he called theEunice plant10 and made the same request.

At 5:50 a.m., the south controller called El Paso Field Services to make sure thatpersonnel there would shut down all compressor units at the South Carlsbad compressorstation.11 The south controller�s shift ended at 6:00 a.m., but he stayed at the gas controlcenter until 8:00 a.m. to provide assistance as necessary. During this time, he notified theEl Paso Energy public relations department in Houston, Texas.12

Emergency Response

Within 5 minutes of the rupture, at 5:31 a.m., the local 911 operator receivednumerous calls from residents reporting a fire and the sound of an explosion. An off-dutyEPNG employee who lived near the site also called 911 and reported the fire. The gascontrol center was called by an off-duty operations specialist when he saw light in the skyfrom the fire, and he also called the pipeline lead operations specialist for the local sectionof the pipeline.

That pipeline lead operations specialist was the first to arrive at the accident site, atabout 5:45 a.m. He said that while he was en route, he had spoken with the gas controlcenter and the EPNG general dispatcher from his truck and had asked the control center tocall managers for the Jal and Carlsbad complexes. He recalled that as he neared the PecosRiver compressor station, the fire was so bright that he had trouble seeing the road.

He then went to the pipeline on the west side of the Pecos River compressor stationand began closing valves that were downstream from the fire. As he closed block (shutoff)valve No. 6 3/4 on line 1100, the operations specialist who had telephoned him earlierarrived, and the two men closed block valves No. 6 3/4 on lines 1103 and 1110. They alsoclosed the pig launcher valves on these pipelines.13

The pipeline lead operations specialist and the operations specialist then drovetheir trucks to the west side of the service bridge and viewed the fire across the river, but

9 The Keystone compressor station, an attended station about 57 miles east and upstream of the PecosRiver compressor station, supplied gas to the Pecos River compressor station through lines 1103 and 1110.

10 The Eunice plant, an attended station about 53 miles northeast and upstream of the Pecos River Riverstation, supplied gas to the Pecos River compressor station through line 1100.

11 The South Carlsbad compressor station, an attended station about 25 miles north and upstream of thePecos station, supplied gas to the Pecos River compressor station through line 3191.

12 Notifying the public relations department, which was responsible for responding to inquiriesregarding events involving the company, was part of EPNG�s emergency response procedures.

13 Pig refers to any of a variety of mechanical devices that can be introduced into a pipeline systemeither to clean the pipeline or, through use of various detection technologies, to identify possible pipelinedefects. Pig launchers and pig receivers in lines 1100, 1103, and 1110 at the time of the accident were usedonly for cleaning pigs.


they could not determine which line had ruptured. The pipeline lead operations specialistsaid he then told the operations specialist to go around to the other side of the river andattempt to determine which line had failed.

The operations specialist said he drove across the river at the low-water crossingand viewed the scene, but because of the proximity of the lines to one another and the fire,he could not determine which line had ruptured. The operations specialist said that as hewas returning to where he left the pipeline lead operations specialist, he thought he mayhave seen vehicles in the fire area just south of the bridge. He continued back across theriver to assist the pipeline lead operations specialist and also told him about the possibilityof vehicles in the fire area. The pipeline lead operations specialist said he told theoperations specialist that they had to get the fire contained and that until that time, therewas nothing they could do. Both employees knew community emergency responders werewaiting at the entrance of the compressor station.

The two men then drove toward the low-water crossing, proceeding down theright-of-way road toward the fire. The pipeline lead operations specialist later recalled thatwhen they arrived at the location where they were going to try to close the block valvesupstream of the fire, he carefully opened the door of his truck to confirm that he couldtolerate the heat. About 6:05 a.m., the two employees left their vehicles and proceeded tothe block valves. The pipeline lead operations specialist closed the No. 5 valve on line1100, but closing this valve did not reduce the intensity of the fire. Together they closedblock valve No. 6 on line 1103, and the operations specialist closed block valve No. 6 online 1110. The fire�s intensity was noticeably reduced after valve No. 6 on line 1103 wasclosed, but the fire continued to burn at the lowered intensity. The pipeline lead operationsspecialist told the operations specialist to check the bypass valve on the pig receiver14 online 1103 and after it was closed, the fire subsided altogether over a period of severalminutes. At about 6:21 a.m., the pipeline lead operations specialist called the gas controlcenter and reported the status of the valves and that the fire was out.

The pipeline lead operations specialist then told the operations specialist to goback to the west side of the river and prevent traffic from entering the area. The operationsspecialist said that as he passed where he thought he may have seen the vehicles during thefire, he now clearly saw burned pickup trucks. He stopped and called the pipeline leadoperations specialist to tell him there were casualties. The pipeline lead operationsspecialist then notified his supervisor and told him to call for more ambulances.

The operations specialist took a first-aid kit from his truck and started down onfoot to check on survivors. At this time, the station lead operations specialist pulled upbehind his truck. He knew where the operations specialist was because he had beenmonitoring radio traffic. After the two men discussed the situation, the operationsspecialist went to assist the victims while the station lead operations specialist drove backto where he knew fire and emergency medical personnel were waiting. He then led anambulance to the fire area. The pipeline lead operations specialist said he drove to the

14 The pig receiver is an arrangement of pipe and valves connected to the pipeline that allows a pig tobe removed from the pipeline.


location of the No. 6 3/4 block valves and, with the assistance of two other EPNGemployees, closed a valve that double-blocked line 1110 (to prevent gas from entering thestation in case one of the block valves on the line was leaking).

The station pipeline specialist had been called by the gas control center as soon asthe Pecos River compressor station shut down at about 5:30 a.m. to determine if theproblem was at the station. When he arrived at the entrance road to the compressor stationoff Whitethorn Road at about 6:10 a.m., he met the two operations specialists he hadtelephoned earlier and saw the Loving Fire Department vehicles on Whitethorn Road atthe entrance driveway to the compressor station. He turned into the entrance road, enteredthe compressor station, and went to the control room to inspect the equipment. He said heknew that power was off at the station because no lights were available in the controlroom. He said that the automatic emergency shutdown system had vented gas from thestation, shut off electrical service, and started the battery-powered cool-down pumps onthe compressors. He and the two operations specialists then crossed the road to the 3191block valve for the South Carlsbad line. This valve was just outside the east fence of thecompressor station where line 3191 connects to lines 1103 and 1110. They finishedclosing the block valve at about 6:16 a.m., thereby isolating the South Carlsbadcompressor station from the Pecos River station and from lines 1103 and 1110. The stationlead operations specialist telephoned the gas control center and informed personnel therethat the valve was closed and that the South Carlsbad compressor station should be takenoff line. The station lead operations specialist sent the other two employees back toWhitethorn Road to help with crowd control as needed.

At about 5:51, the first emergency responders arrived on scene and staged onWhitethorn Road where the driveway into the Pecos River compressor station intersectsthe road. Additional emergency responders also staged at this location, which is about 3/4mile from the accident site. The Carlsbad Fire Department�s medic units had responded tothe initial call and proceeded as far as the Pecos River compressor station. They remainedthere until an ambulance was directed to the victims and EPNG employees admitted thesmaller fire vehicles.15 When one of the fire engines entered the unpaved road from thewest during the fire before the No. 6 block valves were closed, the station lead pipelineoperations specialist stopped them from going farther. He told fireman to stand by whilehe shut more valves. As police cars arrived at that location, he told them to go back to therailroad tracks and let only EPNG vehicles or vehicles with flashing red lights through.Emergency vehicles were admitted as needed to the accident scene after the fire at theruptured line was out.

The victims were camped about 675 feet from the crater, between the crater andthe river. Emergency personnel located victims with the assistance of the operationsspecialist. Six victims were found at the camping area; six others had gone into the riverand were either in the river or had been assisted to the banks by the operations specialist.Paramedics and emergency medical technicians worked to treat the injuries. Volunteer

15 The station lead operations specialist was concerned that the larger fire fighting equipment wouldbecome stuck on the sandy access road.


firefighters and the crews of Carlsbad medic units then evacuated the six victims tohospital burn centers in Texas. None of the victims survived.

The New Mexico State Police responded to the accident and assumedresponsibility for emergency management of the incident. Police personnel also providedsupport to Safety Board personnel during the on-scene investigation. EPNG reported theaccident to the National Response Center at 8:27 a.m.

Pipeline Operations After the Rupture

EPNG gas controllers called gas suppliers to inform them of the problem and torequest that gas supplies into the affected part of the EPNG system be reduced orsuspended due to the incident and the immediate need to shut in all three lines. While onlyone pipeline ruptured, two other pipelines (1100 and 1110) near the rupture site were shutdown and inspected for damage. All compressors at Keystone compressor station �A�plant, as well as Unit 3 at the Keystone compressor station �B� plant, which had beendelivering gas toward the Pecos River, were off by 6:25 a.m.

Meanwhile, the gas control center was in the process of rebalancing the southpipeline system to compensate for the isolated Pecos River compressor station. At about6:10 a.m., the gas control center directed personnel at the Washington Ranch storagefacility16 to stop injecting gas into the storage field and to begin withdrawing gas from thefield. Withdrawing gas from storage allowed EPNG to continue to send gas west.

Postaccident On-Site Inspection

The force of the rupture and the violent ignition of the escaping gas created a 51-foot-wide crater about 113 feet along the pipe. A 49-foot section of the pipe was ejectedfrom the crater in three pieces measuring approximately 3 feet, 20 feet, and 26 feet inlength. (See figure 6.) The largest piece was found about 287 feet northwest of the craterin the direction of the suspension bridges. Investigators visually examined the pipelinethat remained in the crater as well as the three ejected pieces. All three ejected piecesshowed evidence of internal corrosion damage, but one of the pieces showed significantlymore corrosion damage than the other two. Pits were visible on the inside surface of thispiece, and at various locations, the pipe wall evidenced significant thinning. At onelocation, a through-wall perforation was visible. No significant corrosion damage wasvisible on the outside surfaces of the three pieces or on the two ends of the pipelineremaining in the crater. Pieces were cut from the ruptured pipeline segments and shippedto the Safety Board�s Materials Laboratory in Washington, D.C., for further evaluation.(That evaluation is discussed in the �Tests and Research� section of this report.)

16 Washington Ranch storage facility, an attended facility about 24 miles west and downstream of thePecos River compressor station, received and delivered gas through lines 1100, 1103, and 1110.


The drip17 between block valve No. 6 and the rupture site was removed from thepipeline and visually examined. The drip was found to contain a blackish oily-powdery/grainy material. At the area of its heaviest concentration, about 13 feet from thedrip opening, this material filled approximately 70 percent of the cross-sectional area ofthe drip. No significant material was observed in the area just underneath and severalinches away from the siphon drain at the closed end of the drip. No significant internalcorrosion was observed in the drip.

Injuries

All 12 persons who were camping on the east bank of the Pecos River were fatallyinjured in the accident. The causes of death were extensive thermal burns, carbonmonoxide poisoning, and smoke inhalation. (See table 1).

Figure 6. Looking west at a portion of the crater created by the rupture. The missing section of pipe between the arrows was ejected from the crater.

17 The drip (described in more detail later in this report) was a 40-foot-long stub line that branched offthe bottom of the gas pipeline. The drip was designed to collect liquids and solids that may have built up inthe pipeline during normal transportation of gas or after pigging operations.


Table 1. Injuries

Damages

Approximately 49 feet of the underground portion of line 1103 were ejected inthree pieces from the crater created by the rupture. Two of the pieces of pipe were thrown234 and 287 feet, respectively, from the northwest end of the crater toward the river. Oneof these pieces hit the cables that supported the pipeline suspension bridges across theriver. The concrete anchor blocks for the cables, the cables themselves, and the twosuspension bridge steel structures on the east side of the river were burned, as were theaboveground portions of the pipelines. The two pipelines that were being supported on thebridges (EPNG�s 26-inch line 1100 and the out-of-service 16-inch line 1000) fell andcame to rest on the ground on each side of the river, but neither leaked. The three vehiclesand camping equipment on the east side of the river were destroyed, and vegetation alongboth riverbanks was burned. Based on photographs taken of the fire as it engulfed thesuspension bridges, the height of the flame was calculated to be about 496 feet. EPNG, inits incident report to the Research and Special Programs Administration (RSPA), statedthe cost of the accident was $998,296.

Toxicological Information

Specimens for drug testing were collected from the controllers and the coordinatoron Sunday, August 20. The EPNG substance testing contractor, Behavioral TrainingInstitute, Inc., performed the collections and forwarded the specimens to UniversalToxicology Laboratories in Midland, Texas. The results were reviewed by a medicalreview officer at SurgiMed, P.A., in El Paso, Texas. Tests were negative for the testeddrugs.18

Injury Type Public Employees Total

Fatal 12 0 12

Serious 0 0 0

Minor 0 0 0

Total 12 0 12

49 Code of Federal Regulations (CFR) 830.2 defines fatal injury as �any injury which results in death within 30 days of the accident� and serious injury as �an injury which: (1) requires hospitalization for more than 48 hours, commencing within 7 days from the date the injury was received; (2) results in a fracture of any bone (except simple fractures of fingers, toes, or nose); (3) causes severe hemorrhages, nerve, or tendon damage; (4) involves any internal organ; or (5) involves second- or third-degree burns, or any burn affecting more than 5 percent of the body surface.�

18 Specimens were tested for marijuana, cocaine, opiates, amphetamines, and phencyclidine (PCP).


Tests and Research

Metallurgical ExaminationOn-site examination of the three pieces of pipe that were ejected from the crater at

the rupture site identified severe internal corrosion along the interior bottom of the pipe.(See figure 7.) From these three segments, eight pieces were excised and transported to theSafety Board�s Materials Laboratory in Washington, D.C., for further examination. Theexamination of these pieces revealed no evidence of corrosion on the outside of the pipe orthe internal surface across the top half of the pipe (between the 9 and 3 o�clock positionslooking downstream/west). Severe wall loss due to corrosion was observed on the insideof the pipe at the bottom.

The area of corrosion damage extended 21 feet 5 inches. Sections of the girth(circumferential) and seam (longitudinal) welds that were in the bottom half of the pipeexhibited damage from internal corrosion similar to that found on the bottom pipe wall.The extent of corrosion damage (metal loss and number of pits) was most severe along thebottom of the pipe; the most severely corroded area reduced the original pipe wallthickness by 72 percent. (See figure 8.) The wall of many of the corrosion pits containedstriations that extended around the pit. (See figure 9.) Within this length of corrosiondamage were five circumferential wrinkles19 in the pipe wall on the top of the pipe.

Figure 7. Fractured section of line 1103.

19 A wrinkle is a smooth fold in the pipe wall that may have a single inward or single outwarddisplacement or that may include a sinusoidal waveform with both inward and outward displacements. Thefive wrinkles in this pipe were outward deflections of the pipe wall.


Figure 8. Corrosion pitting on inside of pipe near rupture site.

Figure 9. Microscopic view of corrosion pit showing striations


Examination of the fractures showed that a fracture face extended between theinternal corrosion areas and the external wall of the pipe. The fracture faces resulted fromoverstress separation with no evidence of fatigue cracking or corrosion degradation,indicating that corrosion had not penetrated the wall of the pipe at the rupture point.

Corrosion ProductsThe Safety Board�s Materials Laboratory performed x-ray dispersive spectroscopy

analysis on material removed from corrosion pits and areas containing corrosion damage,both from the inside of the pipe. The analysis found high levels of chlorine and sodium inthe material.

After the accident, corrosion products, deposits, and liquid samples were collectedfrom various locations in the EPNG transmission system and subjected to chemical andmicrobial analysis. Sample collection locations included the Pecos River and Keystonecompressor station inlet scrubbers, the line 1103 drip, the line 1103 pig receiver at valveNo. 6, and the line 1100 pig receiver at valve No. 5. Anaerobic bacteria were present in alldeposit/corrosion product samples, and aerobic bacteria were present in 9 of 11 samples;sulfate-reducing bacteria were detected in 18 of 22 individual tests (10 of 11 samples), andacid-producing bacteria were detected in 10 of 22 individual tests (7 of 11 samples). Thechemical analysis indicated the presence of chlorides in all samples. Chlorideconcentrations exceeding 9,000 parts per million (ppm) were detected in three of foursamples obtained from Line 1103. One of these three samples, obtained from the line 1103pig receiver, showed a chloride concentration of 333,000 ppm, or roughly 33 percent ofthe sample. The fourth sample, collected from the line 1103 drip at a point away from thesiphon drain, showed a chloride concentration of less than 50 ppm.

Samples taken from corrosion pits detected in line 1103 after the accident at a lowpoint in the pipeline (about 2,080 feet downstream of the rupture site) showed positivereactions for all four types of bacteria (sulfate-reducing, acid-producing, anaerobic, andaerobic). At this location, the pipe contained a circumferential wrinkle across the top halfof the pipe and corrosion on the internal surface of the bottom of the pipe.

Additional chemical and microbial tests were conducted by EPNG on samplescollected from various transmission facilities. These data showed the presence ofacid-producing bacteria in all samples obtained from the corrosion pit areas.Concentrations greater than 10,000 cells/ml of acid-producing bacteria were observed in 9out of 13 samples obtained from various pit areas. Only 1 out of these 13 samples showedmicrobial concentration less than 10 cells/ml. Chloride levels of less than 100 ppm wereobserved in 26 of 85 samples. Chloride levels greater than 1,000 ppm were observed in 34of 85 sludge/deposit samples. The highest observed chloride level was 400,000 ppm.

Chemical analyses showed that the pH of the liquid collected at the Pecos Rivercompressor station plant inlet separator scrubber was 6.7 to 6.8. The pH of the liquidcollected at the Keystone compressor station inlet scrubber was 8.2. For the materialcollected at the line 1100 and 1103 pig receivers, the pH level was 6.2 to 6.3. The pH ofthe inside material collected from a low spot on line 1103 west of the rupture was 6.4.


Analysis of the material collected near the siphon drain area of the line 1103 drip showeda pH of 8.9.

Chlorides were observed in all corrosion product/deposit samples. Themorphology of corrosion damage located away from the bottom of the ruptured pipeappeared similar to water line corrosion.

Pipeline 1103

At the time of the accident, EPNG operated more than 10,000 miles of natural gastransmission pipelines involving 59 compressor stations and plants and more than 300compressor units. The company operated three of the four in-service gas pipelines at thePecos River crossing, including line 1103, the pipeline that ruptured in this accident.

The section of pipeline 1103 between the Keystone compressor station and thePecos River compressor station was constructed in 1950 with pipe purchased fromRepublic Steel that had been manufactured in accordance with American PetroleumInstitute standard 5LX, High-Test Line Pipe (first edition, 1948). The pipe was 30-inchoutside diameter (OD), grade X52 (specified minimum yield strength of 52,000 psi20) pipewith a nominal wall thickness of 0.335 inch, with sections of heavier wall pipe at locationssuch as road crossings and block valve assemblies. The longitudinal seam weld in the pipewas a double submerged arc weld. The pipeline was cathodically protected, and thecoating was coal-tar wrap.

The pipeline was operating at approximately 675 pounds per square inch, gauge(psig), at the time of the accident. The maximum allowable operating pressure fromKeystone compressor station to the Pecos River compressor station had been establishedby EPNG at 837 psig.21

Pipeline FeaturesValves. Block valves were spaced along line 1103 between the Keystone and

Pecos River compressor stations at intervals ranging from 1 mile to 19.2 miles. From therupture location, block valve No. 6 at the pig receiver was the closest upstream/east valve(0.25 mile), and block valve No. 6 1/2 at the Pecos River compressor station was theclosest downstream/west valve (0.85 mile).

When pigging facilities, including the pig receiver, were installed in the mid-1970s, the valve then designated block valve No. 6 (a 30-inch gate valve) became thereceiver isolation valve. A new plug valve was installed in the bypass around the pig

20 Although yield strength is expressed in pounds per square inch, this number is an expression of thepipe material strength value, which is not equivalent to a pipe�s internal pressure.

21 Equivalent to a stress level of 72 percent of specified minimum yield strength in the 0.335-inch-wall-thickness pipe.


receiver and was designated block valve No. 6. Block valve No. 6 was 0.25 mileupstream/east of the rupture site.

Line 1103 was cross-connected with other lines upstream of the rupture site asfollows:

� Lines 1103 and 1110 were cross-connected in three places between theKeystone and Pecos River compressor stations upstream/east of the rupturesite.

� Lines 1103 and 1100 were cross-connected between block valve No. 6 and theline 1103 drip.

Crossover to Line 1100. About 720 feet downstream/west of block valve No. 6, a16-inch OD crossover (branch line with valves) cross-connected lines 1103 and 1100. Thecrossover was installed during the original construction of the pipeline. Line 1100 wasequipped with a drip until 1989, at which time the drip was found to be �completely full ofsolidified black solids & oil� and was removed. No internal corrosion was observed.

Line 1103 Drip Assembly. About 990 feet downstream/west of block valve No. 6was a drip, a liquid collection leg buried beneath the pipeline that consisted of about 40feet of 30-inch pipe. (See figure 10.) The leg was buried approximately 7 feet directlybelow the gas pipeline and sloped downward toward a dead end equipped with a siphondrain. The leg functioned to collect liquids and solids during normal transportation or afterpigging operations. Also at this location was a liquid storage tank consisting of a 4,620-gallon aboveground steel tank installed within a concrete dike. The siphon drain in theliquid collection leg of the drip assembly emptied into this tank. (See figure 11.) The tankwas fitted with piping and valves for loading the collected liquids into a truck for disposal.The drip assembly was installed during the original construction of the pipeline. Becauseof the location and design of this drip, cleaning pigs could not be run in the section ofpipeline that ruptured. After the removal of the line 1100 drip in 1989, liquids and solidsmoving down line 1100 toward the Pecos River compressor station during both normaloperations and pigging operations in line 1100 could enter line 1103 upstream of the drip.

Pecos River Crossing. About 2,025 feet downstream/west of block valve No. 6was a steel bridge with a single-lane concrete service road spanning approximately 430feet across the Pecos River. Pipeline 1103 rested on, and was strapped to, horizontal steelsupport members off the side of the north bridge girders.

Gas SuppliersLine 1103. In addition to receiving gas from the Keystone compressor station, line

1103 had been connected to and received gas from other gas suppliers beginning in 1979.Seven receipt points existed between the Keystone and Pecos River compressor stationswhere gas flowed into the line for periods ranging from 6 months to 21 years, but at thetime of the accident, only one active supplier, an interstate transmission pipeline, wasconnected to line 1103.


Line 1110. In addition to the gas entering line 1110 from its connection with line1103, two receipt points flowed gas into line 1110 beginning in 1979 for periods of 14years and 21 years, respectively. At the time of the accident, only one active supplier, thesame interstate transmission pipeline connected to line 1103, was connected to line 1110.

Line 1100. In addition to the gas entering line 1100 from the EPNG�s Eunice plant,25 receipt points flowed gas into line 1100 beginning in 1949 for periods ranging from 11/2 years to 51 years. At the time of the accident, 11 active suppliers were connected toline 1100.

Pigging OperationsWhen pigging facilities were added to line 1103 about 25 years after initial

construction, a pig launcher was installed at block valve No. 2 approximately 10.5 milesdownstream/west of the Keystone compressor station, and a pig receiver was installed atblock valve No. 6. At the time of the accident, the line could be pigged from block valveNo. 2 to block valve No. 6. The line was pigged to remove solids and liquids that hadcollected in the pipeline. According to EPNG, when possible, cleaning pigs were run aminimum of twice per year.

Figure 10. Line 1103 drip after excavation.


Figure 11. Diagram of line 1103 drip.


There was no pig launcher at block valve No. 6 and no pig receiver at Pecos Rivercompressor station. For that reason, and because of a reduced port valve22 and otherpipeline features, including the drip, in the section of the pipeline between block valve No.6 and the Pecos River compressor station, that portion of the pipeline (which included therupture location) could not be pigged.

At the time of the accident, the design of the pipeline was such that liquids andsolids not caught at the pig receiver at block valve No. 6 would continue downstream pastthe block valve assembly to the drip downstream/west of the block valve. EPNG officialssaid gas pressure in the drip was used to blow the material out of the drip after eachpigging operation, causing the materials to move to the adjacent, aboveground storagetank for later removal by truck. This tank was also used in conjunction with the drip online 1110. Officials said that in addition to being emptied after a pigging operation, dripswere blown on the 1st and 17th of each month, although the company did not keep recordsof blowdowns.

According to EPNG, material that remained in the pig receiver after a piggingoperation was blown into a dirt pit through a 6-inch pipe off the bottom of the pig receivernear the closure. This 6-inch pipe also connected to an identical 6-inch pipe, which wasused to blow down the adjacent line 1110 pig receiver into the same disposal pit. Afterabout 1975, the 6-inch blowdown piping to the disposal pit was taken out of service. Aconcrete basin was installed below the closure at the end of the pig receiver, and piggingresidue was removed from the pig receiver via the closure and transferred to portablefiberglass containers for disposal. There were no drain lines or liquid storage legsconnected to the pig receiver, as the downstream drip served to collect the pig liquids.

In the 3 years before the accident, line 1103 was pigged from near block valve No.2 to block valve No. 6 four times in 1997, three times in 1998, once in 1999, and once in2000 before the accident. Records for each pig run noted �no solids/liquids reported,�except for the 1999 cleaning, for which �2100 lbs solid/2 barrels oil� was reported. In2001, EPNG notified both RSPA and the Safety Board that the 1999 report of �2100 lbs�was more likely �20 lbs.�

According to EPNG officials, fluids and sludge recovered after the piggingoperations were sent to the EPNG laboratory in El Paso, Texas, and analyzed forhazardous components before disposal. Results of the analysis were provided to thecomplex manager and to the environmental compliance engineer responsible for thecomplex. Test results were also provided to the principal coordinator, corrosion services,and retained at the laboratory. The materials were not tested to determine if they werepotentially corrosive to the pipeline. The laboratory superintendent for the EPNGchemistry laboratory stated that samples from pigging and other inspections had waterconcentrations ranging from trace amounts (less than 1 percent) to 10 percent.

22 The opening in a reduced port valve is smaller than the actual valve size, which prevents a pig frompassing through the valve. For example, the passage through a 30-inch valve could be a 24-inch-diameteropening.


At the Pecos River compressor station, four inlet scrubbers removed liquids fromthe gas stream entering the station from lines 1100, 1103, and 1110. The collected liquidswere analyzed in the same manner as pig liquids. The materials were not tested todetermine if they were potentially corrosive to the pipeline.

In July 1997, because of a recent rupture of line 1300 due to internal corrosion,EPNG conducted an in-line inspection (using a �smart pig� internal inspection tool) of a70-mile section of line 1300. According to EPNG, this inspection found no areas ofinternal corrosion requiring repair, but a visual inspection of the pipeline in the immediatearea of the rupture found an area of internal corrosion, which was repaired. In June andJuly 1998, 33 miles of line 1103 and 33 miles of line 1100, which included a segment ofpipe in which a rupture had recently occurred, were inspected with an in-line inspectiontool. The inspected segments of lines 1100 and 1103 were downstream of the Pecos Rivercompressor station. No areas of internal corrosion requiring repair were discovered. InFebruary 2000, EPNG conducted in-line inspections of 33 miles of lines 3133/3137upstream of Goldsmith Plant in Texas. No areas of internal corrosion requiring repair werediscovered.

Tests and InspectionsThe line 1103 right-of-way had most recently (before the accident) been inspected

on August 11, 2000, by aerial patrol and on August 18, 2000, by ground patrol. Inspectorslooked for evidence of leaks (such as discolored soil or dying vegetation), erosion, andexcavation near the pipeline. No leaks were reported.

Before the accident, the segment of line 1103 between the Pecos River andKeystone compressor stations had never been internally inspected, nor had it beenpressure-tested except for two segments, totaling approximately 0.9 mile locatedapproximately 46 miles upstream of the rupture location, that had been hydrostaticallytested.23

EPNG�s Internal Corrosion Program

According to EPNG, before the accident, the company monitored and mitigatedinternal corrosion by controlling the quality of gas entering the pipeline, by visuallyinspecting the inside of exposed pipe (and, under certain conditions, performing anultrasound test to determine pipe wall thickness), by running cleaning pigs through thepipeline to remove liquids, and by blowing down the drips to remove the liquids and toverify that the drips were functioning properly. EPNG officials stated that they believedthat line 1103 was not transporting corrosive gas because the line was receiving �pipeline

23 Current Federal regulations require that gas pipelines be pressure-tested before being placed inservice. These requirements did not exist when line 1103 was constructed, and when the regulations wereissued later, the requirements for pressure-testing did not apply to existing pipelines.


quality� gas and that unusual conditions, such as water in the pipeline, were not beingobserved at the pig receiver or the drip on line 1103.

Gas quality standards were contained in EPNG�s contracts with its gas suppliersbut were not referenced in the company�s corrosion control procedures. Some interconnectlocations had gas quality monitoring, which either closed a valve to stop the flow of gasinto the transmission pipeline or alarmed in the gas control center if the limit of anyspecified contaminant was exceeded. Not all contaminants were monitored at eachmonitoring location.

For line 1103, gas quality monitoring was installed in the discharge of theKeystone compressor station, at the suction to the Pecos River compressor station, and atthe receipt point with the interstate transmission pipeline approximately 17 milesdownstream/west of the Keystone compressor station. This interconnect location had anautomatic closing valve (referred to as a �slam valve�) actuated by high levels ofhydrogen sulfide (H2S), and an alarm actuated by high levels of carbon dioxide (CO2). Noslam valves or alarms were installed at any of the other receipt locations in line 1103between the Keystone and Pecos River compressor stations.

EPNG was not able to provide water vapor data for line 1103 at the discharge fromthe Keystone compressor station for 19 months between 1998 and 2000.24 At this samelocation, records showed that moisture monitoring instrument readings remainedunchanged from July 10 to 16, 1992; October 1 to 18, 1994; August 13 to 25 and 27 to 30,1998. The moisture monitoring instrument at the Pecos River compressor station inlet alsoshowed unchanged readings from July 11 to 17, 1991; June 16 to July 26, 1994; June 28 toJuly 28 and August 1 to 25, 1996. Similarly, moisture monitoring instruments at the PecosRiver compressor station inlet for lines 1100 and 1110 showed periods of unchangedreadings.

For line 1110, gas quality monitoring was installed in the suction to the PecosRiver compressor station and at the receipt point with the interstate transmission pipelineapproximately 17 miles downstream/west of the Keystone compressor station. Thisinterconnect location had a slam valve actuated by high levels of H2S and an alarmactuated by high levels of CO2. At the other receipt location on line 1110 betweenKeystone and Pecos River compressor stations, there was a slam valve actuated by highlevels of H2S and an alarm actuated by high levels of CO2.

For line 1100 between Eunice plant and the Pecos River compressor station, gasquality monitoring was installed on the suction to the Pecos River compressor station.Two of the 26 receipt locations between Eunice plant and the Pecos River compressorstation had slam valves actuated by high levels of H2S and alarms actuated by high levelsof CO2. In the event of an alarm, gas control center personnel notified the pipelinelocation supervisor and a technician would be called out to investigate. The remainingreceipt locations were not equipped with slam valves or alarms.

24 EPNG officials advised the Safety Board that they believed that the monitoring instrumentation wasworking, but that the data were not recorded electronically.


EPNG officials said that at other locations, its personnel periodically (at 1- to 6-month intervals) sampled and analyzed the gas entering the pipeline. There were nowritten requirements that corrosion technicians follow up on reports of out-of-specification gas being received or identify the effect, if any, of this gas on the pipeline.Corrosion coupons25 or corrosion monitoring devices were not used in this section of line1103 because, officials said, the gas was not believed to be corrosive. EPNG did not injectany corrosion inhibitors into line 1103. The program did not require that ultrasonic testingbe performed on the low points of the non-piggable portions of line 1103, and none wasperformed before the accident. According to EPNG, visual inspections of line 1103 in thearea of the Keystone and Pecos River compressor stations that were exposed duringoperations or maintenance activities before the accident had not shown evidence ofinternal corrosion.

Internal Corrosion Control ProceduresProcedures in Effect Before the Accident. Although at the time of the accident,

EPNG was in the process of implementing updated internal corrosion procedures(discussed below), the company�s internal corrosion control program in the period leadingup to the rupture was governed by its Operating and Maintenance Procedures manual.Section 201.2, �Corrosion Control,� dated September 20, 1999, prescribed the minimumcompany requirements for monitoring and protecting metallic structures. The indicatedreferences were 49 Code of Federal Regulations (CFR) 192.451 through 192.491, whichinclude Federal regulations regarding internal corrosion. Most of Section 201.2 related toexternal corrosion. Requirements for an internal corrosion program were as follows:

If corrosive gas is transported or if internal corrosion is found, Corrosion Serviceswill recommend the appropriate corrective action and establish an internalcorrosion monitoring program to determine the effectiveness of mitigationprograms. Internal corrosion mitigation will continue until monitoring and testingdetermines that the source of corrosion has been removed or other correctiveactions have rendered the gas stream non-corrosive. Internal monitoring will beperformed at least twice each calendar year, but with intervals not to exceed 7 1/2months. Additional monitoring will be performed if necessary. A RemedialAction Form will be completed if internal corrosion is discovered on any portionof the pipeline or ancillary components and vessels containing natural gas.

Each time a pipeline or station pipe segment is exposed for any reason, the coatingand pipe will be evaluated and documented. Whenever any pipe is removed froma pipeline, it shall be inspected for internal corrosion. If internal corrosion isfound, the adjacent pipe must be investigated to determine its extent andappropriate measures taken as detailed in these procedures.

25 A corrosion coupon is a small piece of metal with a specially prepared surface for measuringcorrosion rates. Corrosion coupons may be inserted into the pipeline during pipeline operations to helpoperators assess the potential for internal corrosion or to evaluate the effectiveness of corrosion mitigationefforts.


The procedures did not address the factors that should be considered indetermining whether the gas being transported could cause corrosion. The company statedthat the company�s gas quality standard, set forth in its contracts, addressed severalcontaminants, including water, CO2, H2S, and oxygen (O2), but the corrosion controlprocedures did not reference these contaminants or their acceptable limits. In the eventthat it was determined that corrosive gas was being transported or internal corrosion wasoccurring, corrosion-mitigation actions would be taken. But the procedures did not detailhow technicians were to carry out semi-annual monitoring to determine if the corrosionmitigation measures were effective. The procedures did not provide guidance regardinghow internal corrosion would be detected other than through visual inspection of a pipesegment after it had been removed.

Procedures in Effect at the Time of the Accident. EPNG acquired TennecoEnergy in December 1996 and formed El Paso Energy Corporation. In January 2000, ElPaso Energy Corporation acquired Sonat, Inc., another natural gas pipeline company.26 ElPaso Energy Corporation then assembled teams of representatives from each pipelinecompany and tasked them with establishing best practices and producing a commonoperating and maintenance manual. This new manual was issued on May 15, 2000. Thenew Corrosion Control Manual, which detailed the requirements for internal corrosioncontrol and monitoring, was issued on July 10, 2000.

The section of the Corrosion Control Manual applicable to internal corrosioncontrol was Section 700, �Internal Corrosion Control.� The applicable sections of theOperating and Maintenance Procedures manual were Sections 308.1, �Corrosion,General and Records,� and 308.3, �Internal Corrosion Control.� References included inthese sections were 49 CFR 192.453, 192.475, and 192.477, which address Federalrequirements for internal corrosion control and monitoring.

Section 308.3 of the manual required that gas and liquids be tested to determine ifthey are corrosive and required further steps to minimize the possibility of internalcorrosion. Section 700 of the Corrosion Control Manual included a statement that qualitystandards for gas and liquids entering the pipeline represent the first line of defenseagainst internal corrosion and noted that only by regular monitoring and analysis can it bedetermined if a pipeline is carrying corrosive gas. Detailed descriptions in section 700 forsampling procedures indicate that sampling and analysis of gas, liquids, and solidsremoved from the pipeline is required.

Section 700 also contained a discussion of corrosive constituents in gas streams;listed the company�s typical gas and liquid quality standards, velocity standards, andcorrosion coupon and inhibitor guidelines; schedules for pipeline liquid, gas, and solidsampling; and requirements for preservation of evidence after a leak or failure. Also notedin the documents was that water and other corrosives may enter the pipeline by accident ormay gradually accumulate in low spots despite gas quality monitoring that shows

26 After acquiring Coastal Corporation in January 2001, El Paso Energy Corporation became El PasoCorporation. The El Paso Corporation pipeline system now consists of more than 46,000 miles of gastransmission pipelines.


adherence to quality standards. It also included the basic regulatory requirements thatcorrosive gas may not be transported by pipeline unless the effect of the gas on thepipeline has been investigated and steps have been taken to minimize internal corrosion;that the internal surface of a pipeline be inspected whenever the pipe is exposed andopened; and that coupons or other means be used to determine the effectiveness of thesteps taken to minimize internal corrosion.

Before July 10, 2000, the EPNG operating and maintenance standards did notaddress the relationship of flow velocity to liquid accumulation in a pipeline. TheCorrosion Control Manual dated July 10, 2000, included a velocity standards subsectionthat stated the velocity of wet gas (defined as gas containing more water vapor than theamount specified, typically 7 pounds of water per million standard cubic feet of gas) in apipeline must be limited to avoid solids-erosion or erosion-corrosion. The procedurerequired that consideration be given to flow patterns in the pipeline when evaluating liquidtransported by gas. Flow patterns were described for velocities less than 7.5 feet persecond (dormant pools in a dry gas stream occur), 7.5 to 15 feet per second (agitated poolsand minor spray occur), 15 to 25 feet per second (continuous stream along the bottom ofthe pipe, small agitated pools, and spray occur), and greater than 25 feet per second (noliquids, only spray occurs).

Gas velocity data provided by EPNG for the period 1991 to 2001 indicates that gasvelocities in line 1103 ranged from 2 to 33 feet per second. Typical velocities ranged froma low of 2 to 7 feet per second to a high of 15 to 23 between 1993 and 2000, withvelocities as high as 33 feet per second in 1991 and 1992.

At the time of the rupture, El Paso Energy was in the process of implementing theJuly 10, 2000, corrosion procedures in Section 700 of the Corrosion Control Manual andhad conducted a training session for corrosion technicians in El Paso during the first weekof August 2000. Other personnel assigned corrosion control responsibilities werescheduled for training at a later date.

After the accident, EPNG revised the sections of the Operating and MaintenanceProcedures and the Corrosion Control Manual that affect internal corrosion control.EPNG�s current manual (Corrosion Control Manual, Section 6, effectiveDecember 31, 2001) states �identification of corrosive gas in a pipeline is achieved byanalysis of operating conditions, gas impurity content, monitoring data, mitigationschemes, and/or other considerations� and that �an effective internal corrosion-monitoringprogram includes sampling and analysis of liquid, gas and solid materials.�

Internal Audit ProgramEPNG�s Quality Assurance Auditing Procedures Manual (February 4, 1999,

revised March 3, 1999) describes the company�s internal audit program. For internalcorrosion, the pipeline and plant/stations sections of the manual have a section entitled�Corrosion Control�Internal Coupons.� Answers to the following questions are requiredfor the audit:


Is corrosive gas being transported? If so, has the effect of the gas on the pipelinebeen investigated? What steps have been taken to minimize internal corrosion?Corrosion inhibitor? Dehydration? Have internal coupons been installed tomonitor the effectiveness of the corrosion-mitigating program? If so, are thecoupons checked two times each calendar year at intervals not exceeding 7-1/2months? Is the mil loss per year acceptable?

Preprinted forms were provided in the manual for the auditor to record the resultsof an internal audit. For pipelines, these forms did not list the internal corrosion itemsidentified in the audit questions or provide a space for the auditor to document the resultsof the internal corrosion portion of the audit.

An EPNG senior safety staff member who conducted internal audits toldinvestigators that auditors relied on the location manager/superintendent to tell themwhether or not corrosive gas was being transported through the pipeline. This employeestated that he was aware that gas quality specifications existed, but he did not know whatthey were or what EPNG would consider to be corrosive gas per these specifications. InSeptember 1996, EPNG�s line 1300 ruptured because of internal corrosion. The seniorsafety staff member stated that previous internal audits had not found indications thatinternal corrosion may be occurring in line 1300 or that the use of corrosion coupons orother monitoring methods were needed in the line. In addition, he stated that after therupture of line 1300, the internal audit program was not revised.

Regulatory Oversight

Federal Safety StandardsRSPA promulgates regulations that establish minimum standards for the

transportation of natural gas by pipeline. The regulations for internal corrosion control forgas transmission pipelines in effect at the time of the accident are in 49 CFR Part 192,�Transportation of Natural and Other Gas by Pipeline: Minimum Federal SafetyStandards,� as follows:

Subpart L, 192.605 Procedural manual for operations, maintenance, andemergencies

Each operator shall include the following in its operating and maintenance plan:

(a) General. Each operator shall prepare and follow for each pipeline, a manual ofwritten procedures for conducting operations and maintenance activities and foremergency response. For transmission lines, the manual must also includeprocedures for handling abnormal operations. This manual must be reviewed andupdated by the operator at intervals not exceeding 15 months, but at least onceeach calendar year. This manual must be prepared before operations of a pipelinesystem commence. Appropriate parts of the manual must be kept at locationswhere operations and maintenance activities are conducted.


(b) Maintenance and normal operations. The manual required by paragraph (a) ofthis section must include procedures for the following, if applicable, to providesafety during maintenance and operations.

(1) Operating, maintaining, and repairing the pipeline in accordancewith each of the requirements of this subpart and Subpart M of thispart.

(2) Controlling corrosion in accordance with the operations andmaintenance requirements of Subpart I of this part.

Subpart I, 192.453 General:

The corrosion control procedures required by §192.605(b)(2), including those forthe design, installation, operation, and maintenance of cathodic protectionsystems, must be carried out by, or under the direction of, a person qualified inpipeline corrosion control methods.

192.475 Internal corrosion control: General:

Corrosive gas may not be transported by pipeline, unless the corrosive effect ofthe gas on the pipeline has been investigated and steps have been taken tominimize internal corrosion.

Whenever any pipe is removed from a pipeline for any reason, the internal surfacemust be inspected for evidence of corrosion. If internal corrosion is found, (1) Theadjacent pipe must be investigated to determine the extent of internal corrosion;(2) Replacement must be made to the extent required by the applicable paragraphsof §§192.485, 192.487 or 192,489; and, (3) Steps must be taken to minimize theinternal corrosion.

Gas containing more than 0.25 grain of hydrogen sulfide per 100 standard cubicfeet (5.8 milligrams/m3) at standard conditions (4 parts per million) may not bestored in pipe-type or bottle-type holders.

Subpart I, 192.477 Internal corrosion control: Monitoring:

If corrosive gas is being transported, coupons or other suitable means must beused to determine the effectiveness of the steps taken to minimize internalcorrosion. Each coupon or other means of monitoring internal corrosion must bechecked two times each calendar year, but with intervals not exceeding 7 1/2months.

The Federal pipeline safety regulations do not include design, construction,operating, or maintenance requirements that address the relationship of water andcorrosive contaminants to internal corrosion in a gas pipeline.


Preaccident Federal Inspections of EPNGFrom June 1990 to August 1998, RSPA�s Office of Pipeline Safety (OPS)

conducted 18 safety inspections of EPNG. Inspections were conducted using a question-and-answer format. Four of these inspections were performed by personnel from theArizona State Corporation Commission, as an agent for the OPS for interstate pipelines.For each of these 18 inspections, compliance with the internal corrosion controlregulations was noted as �satisfactory� or, for items associated with corrosion coupons,�N/A� (not applicable). These inspections were based on an inspection form that typicallyhad six questions related to internal corrosion: (1) Are corrosion control proceduresestablished? (2) Are these procedures under the responsibility of a qualified person? (3)Have coupons been utilized and checked at least twice annually, not to exceed 7.5months? (4) Is gas tested to determine corrosive properties? (5) Whenever a pipe segmentis removed from a pipeline, is it examined for evidence of internal corrosion? (6)Remedial action (if required) to minimize internal corrosion? In each of the inspections,�satisfactory� was entered in response to question 4 regarding testing the gas for corrosiveproperties.

In December 1998, the OPS launched a 3-year pilot program designated the�system integrity inspection pilot program.� EPNG applied for the program in February1999, and after reviewing EPNG�s qualifications, the OPS accepted EPNG into theprogram in April 2000. The system integrity inspection pilot program demonstrationperiod expired at the end of 2001, at which time the program was terminated by the OPS.EPNG remained in the program until that time. The pilot program was an attempt by theOPS to develop a method by which the agency could ensure that a pipeline operator hadan effective, compliance-driven internal audit plan and that the plan was effectivelyimplemented. The program was intended to improve communication and information-sharing between operators and Government and to focus resources on the most importantrisks to pipeline safety.

From July 1999 to September 2000, the OPS conducted eight safety inspections ofEPNG under the system integrity inspection pilot program. For each of these eightinspections, compliance with the internal corrosion control regulations was noted as�satisfactory� or �N/A.� There were four internal corrosion related questions on theinspection report form used for six inspections, and they all were noted �satisfactory�: (1)Does the company maintain a comprehensive corrosion control program and associatedrecords? (2) Is the company�s corrosion program under the direction of a qualified person,with associated records? (3) Are corrosion control procedures in place and do they followPart 192/National Association of Corrosion Engineers (NACE)/industry standards, withassociated records? (4) How is the gathered information reviewed and analyzed?Associated records? OPS memos summarizing several of these inspections noted thatEPNG�s internal audit program was working as designed.

One of these eight inspections was a joint team operation and maintenanceprocedures inspection conducted in April 2000. The form used for this inspection includedfour questions related to internal corrosion. The first was for the operator�s procedure forinternal corrosion control coupon monitoring (rated �Satisfactory�); the second was for


the operator�s procedure for corrosion remedial measures (rated �Satisfactory�); the thirdwas for the records of the coupon monitoring (rated �Not Applicable�); and the fourth wasfor records of the corrosion control remedial measures (rated �Not Applicable�). Therewere no questions or subject areas on the inspection record related to transportingcorrosive gas, the training of internal corrosion control personnel, or the qualifications ofthe person directing the internal corrosion control program, as required by 49 CFR192.453. The OPS summary of this inspection did not identify any deficiencies in internalcorrosion monitoring and control or personnel training. Before August 2000, there wereno enforcement actions against EPNG for its internal corrosion program.

After the accident, the OPS revised the inspection form to include more detailedquestions about internal corrosion. The revised form27 has the following written guidancefor the inspector:

� Proper procedures for transporting corrosive gas?� Is pipe inspected for internal corrosion? If found: is adjacent pipe inspected? Is pipe

replaced if required? Are steps taken to minimize internal corrosion?� Internal corrosion control coupon monitoring (2 times per year / 7 1/2 months)� The operator should maintain a comprehensive internal corrosion control program that

includes the following (Best Practice):� Sufficient fluid sample locations throughout their system for monitoring for corrosive

elements.� Does the operator have established threshold limits for various corrosive compounds

in their procedures?� Has the operator identified low points throughout their system where fluids are likely

to accumulate and does the operator identify how to remove the fluids from the lines?� Does the operator specify the frequency in how often the fluids are removed?� Does the operator address fluid accumulation in unpiggable lines? (i.e., fluid samples,

coupons, etc.) (Note: Refer to Advisory Bulletin ADB-00-02, 8/29/00; InternalCorrosion of Gas Pipelines).

Federal Safety Standards and EnforcementMaps and RecordsThe Federal regulations for construction records, maps, and operating history for

gas transmission pipelines in effect at the time of the accident are in 49 CFR Part 192,Subpart L, 192.605, Procedural Manual for Operations, Maintenance, and Emergencies,which includes the following:

(b) Maintenance and normal operations: The manual required by paragraph (a) ofthis section must include procedures for the following, if applicable, to providesafety during maintenance and operations:

(1) ....

27 OPS Form-1 (192-90), �Evaluation Report of Gas Transmission Pipeline,� (Revised 2/01/02 throughamendment 192-90).


(2) �.

(3) Making construction records, maps, and operating history available toappropriate operating personnel.

For the 26 safety inspections of EPNG (referenced earlier) conducted by the OPSfrom June 1990 to September 2000, compliance with 192.605(b)(3) was noted as�satisfactory,� �not applicable,� �not checked,� or, in some cases, the inspection form didnot include questions specifically related to maps and records.

Before August 2000, there were no enforcement actions against EPNG for theirprogram for making construction records, maps, and operating history available tooperating personnel.

Postaccident Actions

Pipeline ReconstructionAfter the accident, EPNG reconstructed lines 1103 and 1110 in the area of the river

crossing. Line 1103 was modified to make it piggable between the Keystone and PecosRiver compressor stations. During hydrostatic testing, line 1103 failed about 2,097 feetdownstream/west of the accident site between the Pecos River and the Pecos Rivercompressor station. At the failure location, pitting was observed on the internal surface ofthe bottom of the pipe, and the wall thickness had been reduced by approximately 69percent. A March 2001 in-line inspection of line 1103, which included the segment inwhich cleaning pigs had been periodically run (from block valve No. 2 to block valveNo. 6) found no areas of internal corrosion that required repair under the internalinspection analysis protocol developed by EPNG and reviewed by the OPS.

Line 1110 was modified to make it piggable from its beginning point on line 1103to the Pecos River compressor station. EPNG investigated nine low points in line 1110between its beginning point on line 1103 and the Pecos River compressor station. Noindications of internal corrosion were found. Some of these low points were in the sectionof line 1110 upstream of block valve No. 6 in which cleaning pigs had been periodicallyrun.

Line 1100 was removed from the suspension bridge, and new 26-inch pipe wasconstructed across the Pecos River and supported off the service bridge. Line 1000, whichpreviously had been abandoned, was removed. The suspension bridges were removed andnot replaced. EPNG modified the power supply to the SCADA computers and modem atPecos River compressor station so that an emergency shutdown would not cause a loss ofpower to the local SCADA computer and modem.


Pipeline Integrity ManagementAfter the accident, EPNG contracted for the development of a program to train

company personnel in internal corrosion. According to EPNG, that program has beencompleted and implemented.

In response to the August 23, 2000, corrective action order (discussed in moredetail below), EPNG identified 60 segments of pipeline where the risk of internalcorrosion was judged to be the greatest. These segments were inspected by in-lineinspection or other non-destructive means with the result that internal corrosion wasdiscovered in eight pipelines. In six of these lines, the company judged the corrosion to beisolated instances. EPNG sent sections of the remaining two pipelines to the company�smetallurgical laboratory for analysis and chemical testing. These tests found a portion ofone of these lines, line 1107, in which general internal corrosion and localized pitting hadreduced the pipe wall thickness by approximately 42 percent. Corrosion product samplestaken from this line were analyzed and found to contain high levels of acid-producingbacteria. Remedial actions were completed before the affected pipelines were returned toservice. On December 4, 2002, the pressure restrictions imposed by the OPS correctiveaction order for lines 1100, 1103, and 1110 were lifted.

After the accident, El Paso Corporation implemented an integrity managementprogram applicable to the company�s 46,000 miles of gas pipelines. An executive-levelcommittee was formed to provide program oversight, and a company-wide pipelineintegrity committee was created to directly supervise and administer the integritymanagement program. The internal corrosion portion of this program includes a system-wide evaluation of flow velocities, low spots in pipelines, drips, vessels, gas qualityhistory, and liquid analysis and other operating and maintenance history and specifiesfollow-up remedial action. Other components of the program include operational audits,the implementation of continuous improvement processes focused on sharing bestpractices, enhanced communication, and the incorporation of performance metrics. Inaddition, the program includes in-line inspection, before 2011, of all onshore pipelines 6-inch-diameter and larger (10,551 miles for EPNG and 42,083 miles total for all pipelinesoperated by El Paso Corporation).

Federal ResponseOn August 23, 2000, RSPA issued a corrective action order (appendix B) to El

Paso Energy Pipeline Group requiring EPNG to take the necessary corrective actions toprotect the public and environment from potential hazards associated with its pipelineoperations. The corrective action order listed 25 required corrective action items.

On August 29, 2000, RSPA issued Advisory Bulletin ADB-00-02 (appendix C) toall operators of natural gas transmission pipelines. This bulletin advised pipeline operatorsto review their internal corrosion monitoring programs and operations and providedguidance for doing so.

On June 20, 2001, the OPS issued to El Paso Energy Pipeline Group a notice ofprobable violation, proposed civil penalty, and proposed compliance order. In the notice,


the OPS stated that preliminary findings indicate that internal corrosion likely played amajor role in the accident. These findings also indicate that internal corrosion hadprobably occurred, over a long period, where liquids had accumulated in a low point in thepipeline.

The five violations alleged in the OPS notice are summarized as follows:

1. EPNG's corrosion control procedure No. 700 for pipelines 1100, 1103, and1110 is not carried out by, or under the direction of, a person qualified in pipelinecorrosion control methods. This is because EPNG's corrosion personnel have notreceived the informal or formal training necessary to perform the tasks required toimplement the corrosion control procedures.

2. EPNG did not take steps to investigate and to minimize internal corrosion, asrequired by 49 CFR 192.475. EPNG failed to follow its procedures when it failedto determine that the gas transported in its pipelines was corrosive. Includes 1�Gas Control failed to recognize when water vapor levels of gas entering thepipeline exceeded Company limits and failed to stop the flow of gas into lines1110 and 1103, 2 � Operations personnel failed to communicate with Corrosionpersonnel about excessive water vapor and liquid water in lines 1103 and 1110, 3� Personnel failed to follow procedures to investigate and take corrective actionswhen the water vapor limits were exceeded in line 1103 and 1110, and 4 �Personnel failed to follow procedures and sound engineering practice by notperforming corrosiveness tests on the liquids and solids that were removed fromlines 1103 and 1110 after pigging operations.

3. EPNG did not follow its procedures for continuing surveillance by failing toconsider and take appropriate action on several unusual operating andmaintenance conditions on line 1103. EPNG failed to test pigging residue forcorrosivity and failed to evaluate line 1103 for low points where liquids couldaccumulate and where corrosion could occur.

4. EPNG did not follow its Leak and Failure Reporting procedure by notfollowing up on the Company's recommendations developed after the Roswellfailure (caused by internal corrosion) and thus not minimizing the likelihood of arecurrence.

5. EPNG did not have an updated drawing of line 1103 because it did not showthe elevation profile of the pipeline in the area of the accident. Having an accurateprofile would have allowed EPNG to determine where low points, and possibleliquid accumulation and internal corrosion, were located.

The notice proposed a civil penalty of $2.525 million for probable safetyviolations. On October 12, 2001, EPNG submitted a detailed response to the notice thataddressed each alleged violation and requested a hearing as set forth in RSPA regulations.As of January 3, 2003, a hearing date had not been set, and a final order had not beenissued.


Pipeline Integrity ManagementFederal Regulations

In 1987, as the result of two gas pipeline accidents28 that killed five persons, theSafety Board made the following safety recommendations to RSPA:

P-87-4

Require operators of both gas and liquid transmission pipelines toperiodically determine the adequacy of their pipelines to operate atestablished maximum allowable pressures by performing inspections ortests capable of identifying corrosion-caused and other time-dependentdamages that may be detrimental to the continued safe operation of thesepipelines and require necessary remedial action.

P-87-5

Establish criteria for use by operators of pipelines in determining thefrequency for performing inspections and tests conducted to determine theappropriateness of established maximum allowable operating pressures.

RSPA most recently responded in April 2002, stating that RSPA now requiresintegrity management programs for hazardous liquid pipelines in high-consequence areas,and that it (1) published a notice in the Federal Register on June 27, 2001, requestingcomments on integrity management concepts for gas transmission pipelines, (2) publisheda proposed definition of high-consequence areas for gas pipelines on January 9, 2002, and(3) would propose a gas pipeline integrity management program later in 2002. On thebasis of this information, Safety Recommendations P-87-4 and -5 were classified�OpenAcceptable Response� pending completion of these actions.

In 1987, as the result of a gasoline pipeline accident29 in which two persons werekilled and one person was seriously burned, the Safety Board made the following safetyrecommendation to RSPA:

P-87-23

Revise 49 CFR parts 192 and 195 to include operational based criteria fordetermining safe service intervals for pipelines between hydrostatic retests.

RSPA most recently responded in an October 11, 2002, letter summarizing theactions the agency has taken regarding pipeline integrity since the recommendation wasissued. The agency told the Safety Board that over a number of years it had developed new

28 National Transportation Safety Board, Texas Eastern Gas Pipeline Company Ruptures and Fires atBeaumont, Kentucky, on April 27, 1985, and Lancaster, Kentucky, on February 21, 1986. Pipeline AccidentReport NTSB/ PAR-87-01 (Washington, D.C.; NTSB, 1987).

29 National Transportation Safety Board, Williams Pipe Line Company Liquid Pipeline Rupture andFire, Mounds Views, Minnesota, July 8, 1986. Pipeline Accident Report NTSB/PAR-87/02 (Washington,D.C.; NTSB, 1987).


approaches and had studied a number of developing technologies that are helping industryto better assess the operation of their pipelines. In addition, the letter stated that RSPA haddeveloped a series of rulemakings that will require every natural gas transmission andhazardous liquid pipeline operator to implement an integrity management program toprotect high-consequence areas that could be affected by a pipeline failure. Based on thisinformation and information contained in an earlier (July 2002) response to thisrecommendation, the Safety Board classified Safety Recommendation P-87-23�OpenAcceptable Response,�30 pending completion of the rulemaking.

Effective September 5, 2002, RSPA issued a final rule (�Pipeline Safety: HighConsequence Areas for Gas Transmission Pipelines�) in which it defined �high-consequence area� as an area within a certain distance of a gas transmission pipeline thatmeet one or more specified criteria for the number of persons or types of property thatmight be affected by an accident involving that pipeline.

On December 17, 2002, the President signed Public Law 107-355, the PipelineSafety Improvement Act of 2002. Section 14 of this act requires that within 12 months ofits enactment, RSPA is to issue a final rule prescribing integrity management standards foroperators of gas transmission pipelines in high-consequence areas. The act requires thatwithin 24 months of its enactment, gas pipeline operators implement integritymanagement programs, even if RPSA has not issued a final rule. The act requires thesepipeline operators to complete integrity testing of 50 percent of the highest risk pipelineswithin 5 years and the remainder within 10 years. Reassessment intervals are set at aminimum of once every 7 years. Integrity testing must be done by in-line inspection,pressure-testing, or an alternative method approved by RSPA as providing at least anequal level of safety. Under certain conditions, RSPA may grant waivers. The act requiresthe integrity programs to have clearly defined criteria for evaluating the results of thetesting in addition to a description of actions to be taken by operators to promptly addressany integrity issues raised by the evaluation.

On January 28, 2003, RSPA published in the Federal Register a notice of proposedrulemaking (NPRM) to require operators of gas transmission pipelines to establishintegrity management programs to identify and evaluate the condition of and threats totheir pipelines in high-consequence areas and to take steps to protect against pipelinefailures. The proposed rule would require these pipeline operators to use periodic in-lineinspections, pressure-testing, direct assessment,31 or other means to identify weaknesses inthe pipe wall. Further, the rule would require operators to gather and evaluate data on theperformance trends resulting from their programs and to make improvements andcorrections based on this evaluation. The rule will not apply to gas gathering or to gasdistribution lines. The proposed rule would also incorporate the required elements for gas

30 Safety Recommendation P-87-23 had previously been classified �OpenUnacceptable Response.�31 Direct assessment is an integrity assessment method that uses a process to evaluate the threats to

pipeline integrity from external corrosion, internal corrosion, and stress corrosion cracking. The processincludes the gathering and integration of risk factor data, indirect examination or analysis to identify areas ofsuspected corrosion, direct examination of the pipeline in these areas, and post-assessment evaluation.


pipeline integrity management programs that are mandated in the Pipeline SafetyImprovement Act.

NACE Standards

NACE International, an organization concerned with corrosion issues, producesconsensus industry standards in the form of test methods, recommended practices, andmaterial requirements. In 1975, the organization issued a standard, RP0175-75, �Controlof Internal Corrosion in Steel Pipelines and Piping Systems.� The purpose of this standardwas to describe procedures and recommended practices for achieving effective control ofinternal corrosion in steel pipe and piping systems in crude oil, refined products, and gasservice. RP0175-75 addressed methods for detecting and controlling internal corrosionand noted the importance of flow velocity analysis, periodic product sampling, andchemical analysis of corrosive constituents in mitigating corrosion. It also identified thebeneficial effects of the use of cleaning pigs.

RP0175-75 was intended to serve as a guide for establishing minimumrequirements for control of internal corrosion in gas transmission, gas distribution, andother steel piping systems. Because the document had not been reviewed and renewed byNACE when it was due for periodic review, in 1995 the document was withdrawn and isavailable from NACE only as a historical document. NACE does not consider RP0175-75to be an official and current NACE document. The Safety Board has been told by NACErepresentatives that the society is working on another standard similar to, and based on,RP0175-75.

ASME Code for Gas Piping (B31.8)32

The American Society of Mechanical Engineers (ASME) code for gas pipingaddresses the safety aspects of the design, construction, operation, and maintenance of gaspipelines. Specific guidance for an internal corrosion control program for all existingpipelines is included. For pipelines that transport corrosive gas, design and constructionconsiderations for new pipelines and modifications to existing pipelines are included. Fordesign and construction, the considerations include (1) running cleaning pigs (includingprovisions for effective accumulation and handling of liquids and solids removed from thepipeline by the pigging), (2) installing corrosion monitoring devices (coupons, probes) atlocations where the greatest potential for corrosion exists, (3) treating the gas to reduce itscorrosivity, (4) selecting corrosion resistant materials for construction of the pipeline, (5)internally coating the pipeline, and (6) injecting corrosion inhibitors into the gas stream.

32 ASME B31.8-1999, Gas Transmission and Distribution Piping Systems, American Society ofMechanical Engineers; Chapter VI, paragraph 863. (Essentially identical wording has been part of ASMEB31.8 since 1982.) On January 31, 2002, ASME issued a supplement to the B31.8 code entitled �ManagingSystem Integrity of Gas Pipelines,� which includes guidance for determining whether internal corrosionmay be a threat to pipeline integrity and measures to assess the condition of the pipeline at those locations.


For operations and maintenance, the considerations include (1) establishing a program forthe detection, prevention, or mitigation of internal corrosion (including reviewing leak andrepair records, inspecting the internal surface of the pipe whenever it becomes accessible,analyzing gas from areas of known internal corrosion to determine the types andconcentrations of corrosive agents, analyzing liquids and solids removed from the pipelineby pigging, and draining or cleanup to determine the presence of corrosive materials andevidence of corrosion products), (2) controlling corrosion by modifying the pipeline tofacilitate the removal of water from low spots, and (3) measuring the wall thickness ofburied pipe when it is uncovered and of exposed pipe in areas where internal corrosion issuspected.

Guide for Gas Transmission and Distribution Piping Systems33

The Gas Piping Technology Committee�s34 Guide for Gas Transmission andDistribution Piping Systems includes material intended to assist the user in complyingwith the Federal regulations.35 For internal corrosion, guidelines for design, detection,monitoring, and corrective measures are included. The guide states that in the presence ofwater, gases containing certain components such as CO2, H2S, and O2 can be corrosive tosteel pipelines and that pipeline liquids may contain constituents that may be detrimentalto pipeline integrity. The guide also states that if it is anticipated or has been determinedthat the gas to be transported is corrosive, the following should be considered: selection ofspecial materials of construction, effect of flow velocities, fluid removal (pigging, dripsthat include access ports for internal inspection, separators), control of water dew point(by dehydration, separation, or temperature control), reduction of corrosive components inthe gas, internal coating, and chemical treatments. For the detection of internal corrosion,considerations include sampling and analysis of gas, liquids, and solids; visual inspectionof pipe and drips; use of corrosion monitoring devices (coupons, probes); and in-lineinspection and other non-destructive inspection to determine wall thickness.

Other Information

Previous EPNG Internal Corrosion AccidentOn September 10, 1996, line 1300 ruptured near Roswell, New Mexico. The

EPNG investigation determined that the pipe had failed from internal corrosion at a sagbend in the pipe. The accident report stated that:

33 ANSI GPTC Z380.1, Guide for Gas Transmission and Distribution Piping Systems, Gas PipingTechnology Committee.

34 The Gas Piping Technology Committee is an independent consensus committee comprisingrepresentatives from the pipeline industry, including manufacturers, operators, and consultants, as well asfrom pipeline regulatory agencies.

35 The current guide is dated June 15, 1998, and includes Addendum No. 1, July 7, 1999; AddendumNo. 2, August 23, 2000; and Addendum No. 3, January 29, 2002. The guide material for internal corrosionwas most recently revised in Addendum 3.


it is impossible to tell when in time most of the corrosion at the rupture pointoccurred. However, it is certainly related to the settlement of liquids in a low spot,possibly during the period of low flows in the line for several years prior to itsreversal in 1992. The source of liquids was probably one or more of theproduction facilities that provide (or provided) gas directly to the transmissionline. Current analyses do not provide adequate information to determine thepresence of potentially corrosive liquids in gas received, so other measures shouldbe taken to prevent the introduction of liquids into the line.

The metallurgy report, which was an attachment to EPNG�s final investigationreport of the rupture, recommended that the quality of gas being injected into line 1300near the rupture location and at other locations of concern be monitored to avoid anotherfailure of this type. Also recommended were (1) that pigs be run near the failure locationto clean any remaining liquid from the system, (2) that a sample of the pigging residue beanalyzed to determine whether undesirable compounds were present, (3) that other areasof possible pipeline deflection be examined, and (4) that previously untested areas in thevicinity of the rupture be hydrostatically tested to ensure their structural integrity.

In a Safety Board interview, a member of the EPNG pipeline safety staff stated thatthe company considered the failure of line 1300 to be an isolated event and that therecommendations in the investigation report were therefore applicable only to line 1300because of unique operating conditions in the ruptured pipeline. These conditions includeda producer that EPNG representatives said had been known to introduce water into thepipeline at a receipt point near the rupture location, as well as periods of low-flow andstatic conditions in line 1300, which resulted in gas flow rates insufficient to move ordissipate the moisture.

Emergency Training and Simulations

Annual meetings of emergency responders were conducted in November 1997,October 1998, October 1999, and October 2000 for the Carlsbad area, including EddyCounty, emergency response and law enforcement agencies. At these meetings, EPNGpersonnel reiterated safety precautions at natural gas emergencies and, through writtentests, quizzed emergency responders on safety issues.

In November 1997, EPNG conducted an emergency response exercise for a leakon line 3191 between South Carlsbad compressor station and Pecos River compressorstation. The Eddy County Sheriff�s Office was involved, as well as the Eddy Countydisaster coordinator. In August 1997, a leak was simulated at the Keystone compressorstation to test the readiness of the compressor station personnel.


Analysis

EPNG pipeline 1103 was operating at about 80 percent of the maximum allowableoperating pressure when the pipeline ruptured. The rupture occurred at a place in thepipeline where internal corrosion had thinned the pipe wall. The fact that the fracture facesresulted from overstress separation with no evidence of fatigue cracking indicates that therupture occurred as one catastrophic event. The Safety Board therefore concludes that line1103 ruptured as a result of severe internal corrosion that caused a reduction in pipe wallthickness to the point that the remaining metal could no longer contain the pressure withinthe pipe.

A number of factors were found to have contributed to the fact that the corrosionthat led to the rupture had not been detected and mitigated by EPNG before the accident,and those factors are addressed in this analysis.

The major safety issues identified during the investigation of this accident are asfollows:

� The design and construction of the pipeline,

� The adequacy of EPNG�s internal corrosion control program,

� The adequacy of Federal safety regulations for gas pipelines, and

� The adequacy of Federal oversight of the pipeline operator.

Exclusions

The investigation determined that the operating pressure (675 psig) in the pipelineat the time of the rupture was below the maximum allowable operating pressure (837 psig)established for that section of the pipeline. Operation of the pipeline system wasmonitored by a SCADA system, and even though the gas controller�s understanding of therapidly unfolding situation at the Pecos River compressor station immediately after therupture was hampered by a brief interruption of data from the SCADA system and thesubsequent loss of SCADA communications as a result of the power outage at the PecosRiver compressor station, the controller accurately evaluated the available informationand promptly initiated an appropriate response. There was no evidence of third-partydamage to the pipeline at the rupture site, nor was there evidence of external corrosion atthe rupture location. The Safety Board therefore concludes that the following were neithercausal nor contributory to the accident or its aftermath: overpressure of the pipeline, theinterruption in or loss of SCADA communication, external damage to the pipeline throughexcavation or other activities, and external corrosion of the pipeline.


Emergency Response

EPNG employees, who were on the accident scene within 19 minutes of therupture, worked quickly and effectively to stop the flow of natural gas from the rupturedpipeline and to extinguish the fire. Because they did not know which pipeline hadruptured, they began closing valves upstream and downstream of the fireball in all fourEPNG natural gas pipelines. Emergency responders arrived on scene within 25 minutes ofthe rupture and staged at the Pecos River compressor station. The emergency respondersanticipated a routine standby assignment that would terminate when the flow of naturalgas was stopped and the fire self-extinguished. Because the accident was in a rural area,emergency responders did not expect to find any persons injured. However, approximately40 minutes after the rupture and while attempting to reach valves to stop the flow ofnatural gas, an EPNG employee thought that he saw vehicles in the area of the fire andprovided that information to another employee.

About 15 minutes later, when the flow of natural gas was stopped and the fire wasextinguished, the EPNG employee confirmed that he had seen vehicles in the area wherethe fire had been burning. This information was then passed on to emergency responders,who immediately initiated rescue efforts. Carlsbad Fire Department�s medic units hadresponded with the initial call and were staged at the compressor station. Paramedics andemergency medical technicians worked diligently to treat the injuries of victims and tohastily evacuate them to hospital burn centers in Texas.

The Safety Board notes that the EPNG employees who initially had informationthat vehicles may be parked in the vicinity of the fire did not notify emergency respondersuntil the fire was extinguished and the presence of vehicles was confirmed. In order foremergency responders to make informed decisions about rescue efforts, it is important thatthey be given information, as quickly as it is available, that could indicate the possibilityof victims in the vicinity of an accident. In this case, because of the intensity of the fire inthe vicinity of the campsite, the radiant heat associated with the fire, and the difficulty thatresponse crews would have faced gaining access to the area while the fire was burning, theSafety Board does not believe the outcome of the accident would have been different ifresponders had been notified sooner, although the precise effect such notification wouldhave had on responders� decision-making cannot be determined.

Internal Corrosion in Steel Gas Pipelines

Corrosion on the internal wall of a natural gas pipeline can occur when the pipewall is exposed to water and contaminants in the gas, such as O2, H2S, CO2, or chlorides.The nature and extent of the corrosion damage that may occur are functions of theconcentration and particular combinations of these various corrosive constituents withinthe pipe, as well as of the operating conditions of the pipeline. For example, gas velocityand temperature in the pipeline play a significant role in determining if and wherecorrosion damage may occur. In other words, a particular gas composition may causecorrosion under some operating conditions but not others. Therefore, it would be difficult

Analysis 40 Pipeline Accident Report

to develop a precise definition of the term �corrosive gas� that would be universallyapplicable under all operating conditions.

Corrosion may also be caused or facilitated by the activity of microorganismsliving on the pipe wall. Referred to as microbiologically influenced corrosion, or MIC,this type of corrosion can occur when microbes and nutrients are available and wherewater, corrosion products, deposits, etc., present on the pipe wall provide sites favorablefor the colonization of microbes. Microbial activity, in turn, may create concentration cellsor produce organic acids or acid-producing gases, making the environment aggressive forcarbon steel. The microbes can also metabolize sulfur or sulfur compounds to produceproducts that are corrosive to steel or that otherwise accelerate the attack on steel.

Internal corrosion in a gas pipeline may be detected by any of several methods,including visual examination of the inside of a pipeline when it is opened, externalmeasurement of the pipe wall thickness with instruments, evaluation of corrosion couponsor probes placed inside the pipeline, or inspection of the pipe with an in-line inspectiontool to identify areas of pitting or metal loss.

Internal corrosion may be kept under control by establishing appropriate pipelineoperating conditions and by using corrosion-mitigation techniques. One method forreducing the potential for internal corrosion to occur is to control the quality of gasentering the pipeline. Also, by periodically sampling and analyzing the gas, liquids, andsolids removed from the pipeline to detect the presence and concentration of any corrosivecontaminants, including bacteria, as well as to detect evidence of corrosion products, apipeline operator can determine if detrimental corrosion may be occurring, identify thecause(s) of the corrosion, and develop corrosion control measures.

Internal Corrosion in Line 1103

Interconnecting pits were observed on the inside of the pipe in the ruptured area ofline 1103. Typically, these pits showed the striations and undercutting features that areoften associated with microbial corrosion. A pit profile showed that chloride concentrationin the pits increased steadily from top to bottom. Increased chloride concentration canresult from certain types of microbial activity. All four types of microbes (sulfate-reducing, acid-producing, general aerobic, and anaerobic) were observed in samplescollected from two pit areas in the piece of line 1103 where internal corrosion wasdiscovered after the accident about 2,080 feet downstream of the rupture site. Though theindividual contribution of various microbes in the corrosion process could not beestimated, the damage morphology and the corrosion product analyses data suggest thatmicrobiological activity contributed to the corrosion process.

Dissolved O2 in an electrolyte could cause pitting by creating concentration cells.CO2 is soluble in water and will form carbonic acid, which is corrosive to carbon steel.


When dissolved in water, H2S forms a weak acid that could corrode carbon steel.In combination with dissolved O2, it could cause pitting. Though generally present in lowconcentrations, these potentially corrosive constituents were present in the gas that wasbeing transported in line 1103. Also, upset conditions occasionally increased theconcentrations of these constituents in the transported gas.

Chlorides were observed in all corrosion product/deposit samples. Anions, such aschloride, cause pitting and, typically, chloride concentration in a pit may be much higherthan the chloride concentration outside the pit (bulk concentration).

Chemical analyses showed that the pH (6.7-6.8) of the liquid collected at the PecosRiver compressor station plant inlet separator scrubber was more acidic than the pH (8.2)of the liquid collected at Keystone compressor station inlet scrubber. Also, the materialcollected at line 1100 and 1103 pig receivers (pH ~ 6.2-6.3) and the inside materialcollected from a low spot on line 1103 west of the rupture (pH ~ 6.4) were more acidicthan the material collected near the siphon drain area of the line 1103 drip (pH ~ 8.9). Theobserved low pH in the samples could be a result of dissolved CO2, and/or H2S in thewater, and/or intrusion of low-pH ground water into the gas supply. Typically, acidic(pH<7) water is more corrosive to carbon steel than basic water (pH>7).

Thus, water and contaminants such as chlorides, O2, CO2, and H2S all likelycontributed to the observed corrosion damage. The Safety Board therefore concludes thatthe corrosion that was found in line 1103 at the rupture site was likely caused by acombination within the pipeline of microbes and such contaminants as moisture,chlorides, O2, CO2, and H2S.

Physical Features of Line 1103

Examination of the pipe at the rupture location revealed five wrinkles in the pipewall at the top of the pipeline. Wrinkles in the wall of a pipe occur when a pipe is bent,either to align pieces of pipe during construction or from external forces, such as earthmovement, after the pipeline is in service. When pipe is bent and wrinkles form on the topof the pipe, a low point is created at the bottom of the pipe opposite the wrinkles. Theobserved internal corrosion in the pipeline at the rupture location was at such a low point,where liquids likely accumulated into a pool with a fluctuating liquid level. Because thedensity of water is greater than that of hydrocarbon liquids present in the pipeline, water inthe pipeline would remain at the bottom of the pool with the liquid hydrocarbons on top,creating an ideal environment for the development of internal corrosion.

The original construction of line 1103 by EPNG included a block valve and dripapproximately 1 mile east of the Pecos River. The block valve, designated No. 6, was on ahill about 62 feet higher than the Pecos River. The valve may have been positioned thus sothat it would remain accessible and not be damaged if the river flooded. The undergrounddrip was placed downstream of the block valve and was 31 feet lower in elevation than thepipeline at block valve No. 6. This configuration facilitated the trapping of liquids and


solids flowing in line 1103 toward the Pecos River compressor station by the drip, whichwas upstream of the rupture location.

When pigging facilities were added to line 1103 about 25 years after initialconstruction, a pig launcher was installed at block valve No. 2, and a pig receiver wasplaced at block valve No. 6. A separate storage leg or tank to collect the pig liquids atblock valve No. 6 was not installed. Instead, during pigging operations, the pig and someof the liquids and solids being pushed by the pig would be caught in the pig receiver atblock valve No. 6. Any material that passed the pig receiver, either during normaloperations or because of a pig run, would flow downstream and downhill to the drip.

Postaccident visual examination of the drip revealed that, at one point, about 70percent of the drip cross-section was filled with the blackish oily-powdery/grainy materialthat acted as a dam inside the drip, preventing some of the materials entering the drip fromcontinuing to the far end of the barrel to the siphon drain. This blockage also likelycontributed to movement of liquids and solids past the drip. Materials flowing past thedrip could then collect at low points in the downstream pipeline, such as the low point atthe rupture location, where they would remain until gas flow of sufficient velocity wasavailable to sweep the liquids farther downstream toward the inlet scrubbers at the PecosRiver compressor station. Velocity data provided by EPNG for the period 1991 to 2000indicated numerous periods when the gas velocity was substantially below the preferredsweeping velocity of 25 feet per second.

The Safety Board concludes that, as a likely result of the partial clogging of thedrip upstream of the rupture location, some liquids bypassed the drip, continued throughthe pipeline, and accumulated and caused corrosion at the eventual rupture site where pipebending had created a low point in the pipeline.

Periodic use of cleaning pigs can remove water and other liquid and solidcontaminants from a pipeline. One of the considerations for the design and construction ofa cleaning pig system is to make provisions for effective collection and removal of theaccumulated materials from the pipeline after pigging. In line 1103, because of theconfiguration of the piping and valves at block valve No. 6 and the geometry of the drip,cleaning pigs could not be run in the section of pipeline that ruptured. Some of the liquidsand solids that accumulated in front of the cleaning pig were returned to the pipeline andmoved downstream by the flowing gas toward the drip. In conjunction with the partiallyclogged drip, and the introduction of additional liquids into line 1103 from the crossoverfrom line 1100 (from which the drip had been removed) upstream of the line 1103 drip, itis likely that there was incomplete removal of accumulated liquids and solids from line1103.

Postaccident in-line inspection of the segment of line 1103 in which cleaning pigshad been periodically run (from block valve No. 2 to block valve No. 6) found no areas ofinternal corrosion that the company determined required repair. The Safety Boardtherefore concludes that if the accident section of pipeline 1103 had been able toaccommodate cleaning pigs, and if cleaning pigs had been used regularly with theresulting liquids and solids thoroughly removed from the pipeline after each pig run, the


internal corrosion that developed in this section of pipe would likely have been lesssevere.

The ASME code for gas piping (ASME B31.8, Gas Transmission and DistributionPiping Systems) and the Guide for Gas Transmission and Distribution Piping Systemsinclude design and construction considerations related to internal corrosion control fornew pipelines and modifications to existing pipelines. Although some operators mayincorporate these considerations or have their own engineering standards for the designand construction of pipelines to minimize liquid accumulation and to remove liquids froma pipeline, there are no Federal regulatory requirements applicable to all operators.

The Safety Board believes that RSPA should revise 49 CFR Part 192 to requirethat new or replaced pipelines be designed and constructed with features to mitigateinternal corrosion. At a minimum, such pipelines should (1) be configured to minimize theaccumulation of liquids, (2) be equipped with effective liquid removal features, and (3) beable to accommodate corrosion monitoring devices at locations with the greatest potentialfor internal corrosion.

EPNG Internal Corrosion Control Program

At the time of the accident, EPNG was beginning the process of implementing aninternal corrosion control program based on the new procedures dated May 15, 2000, andJuly 10, 2000. However, training of personnel in the new procedures began in August2000, and the new corrosion control actions specified in these documents had yet to befully implemented at the time of the accident. As a result, the program actually in placewas the one specified in the September 20, 1999, operating and maintenance proceduresmanual. This written program required (1) that the corrosion services department, afterbeing notified that corrosive gas was being transported or if internal corrosion was found,recommend appropriate corrective actions and establish an internal corrosion monitoringprogram to determine the effectiveness of the corrective actions, and (2) that a visualinspection he made of the inside of a pipeline when opened.

These procedures did not address the specific operating conditions, such as waterin the pipeline, corrosive contaminants in the gas and liquid, and velocity of the gas, thatshould be considered when evaluating a pipeline for possible internal corrosion. Thecompany�s gas quality standard addressed several contaminants, including water, CO2,H2S, and O2, but the corrosion control procedures did not reference these contaminants ortheir acceptable limits. Although gas quality standards were contained in EPNG�scontracts with gas suppliers, most of the interconnect locations with gas producers on line1103 (between the Pecos River compressor station and the Keystone compressor station)and line 1100 (between Eunice plant and the Keystone compressor station, from which gasand liquids could enter line 1103 upstream of the drip) did not have alarms (which alarmedin the gas control center if contaminant levels were exceeded), and other locations onlyhad periodic sampling and analysis of the gas entering the EPNG pipeline. Thus, despitethe fact that EPNG officials said they relied partially on maintaining the quality of gas to


help prevent corrosion, the company did not take the steps necessary to allow it toadequately monitor and control the quality of gas entering the pipeline.

The 1999 procedures did not provide guidance regarding how internal corrosionwould be detected other than through visual inspection of a pipe segment after it had beenopened. Nor did the procedures require that, during normal operations, pigging, ormaintenance activities, liquids and solids be removed from the pipeline and tested for thepresence of corrosive materials or evidence of corrosion products. The ASME B31.8 codeidentifies the importance of determining whether gas is corrosive by requiring that �Gascontaining free water under the conditions at which it will be transported shall be assumedto be corrosive, unless proven to be non-corrosive by recognized tests or experience.�Very little useful information concerning what was entering the pipeline, where it wasentering, and what materials were accumulating in the pipeline was available to corrosioncontrol personnel. As a result, EPNG corrosion control personnel stated that they were notaware that corrosion could be occurring in the company�s pipeline or that corrosionmitigation measures might be necessary.

In the event it was determined that corrosive gas was being transported or internalcorrosion was occurring, corrosion mitigation actions would be recommended by thecorrosion services department. However, there were no written requirements for corrosiontechnicians to follow up on reports of out-of-specification gas being received or to identifythe effect, if any, of this gas on the pipeline, and there were no standards or criteria to beused to determine if out-of-specification gas was potentially corrosive. The procedures didnot detail how the semi-annual monitoring to determine the effectiveness of the corrosionmitigation measures would be carried out. Corrosion monitoring devices were not used inline 1103 between the Keystone and Pecos River stations because the gas was not believedto be corrosive.

In September 1996, EPNG�s line 1300 ruptured as a result of internal corrosion.The metallurgy report attached to EPNG�s final investigation report of the rupturerecommended expanded gas quality monitoring and additional pigging, with collectedresidue being analyzed for undesirable components. Because the company considered thisrupture to be an isolated event, it did not implement the recommendations for its other,similar, gas transmission lines. Further, according to a senior safety staff employee atEPNG, the company�s internal audit program was not revised after the September 1996rupture of line 1300 from internal corrosion. Revising the company�s audit program toinclude inquiries regarding operating conditions (gas velocity, gas producers connected toa transmission pipeline, unpigged pipelines whose configuration could lead toaccumulation of liquids in low spots) would have helped EPNG to determine if similarconditions existed in other pipelines, but the company did not do so.

In the years leading up to the accident, EPNG had access to industry standards andguidelines, such as those contained in the NACE standards, the ASME code, and theGuide for Gas Transmission and Distribution Piping Systems, regarding the detection andcontrol of internal pipeline corrosion. But the company did not incorporate that guidancein its internal corrosion procedures. Nor did the company take the steps necessary toensure that the limited procedures that it did have in place were effective. For example,


while the procedures in place at the time of the accident stated that corrosion controlpersonnel were to be notified if corrosive gas was being transported, the company did not,as noted above, carry out the gas quality monitoring or inspection activities necessary tomake an accurate determination of the corrosivity of the gas. Also, the proceduresrequired that corrosion control personnel be notified if corrosion was found, but thecompany had no systematic program to detect possible internal corrosion. Internalinspection devices or corrosion coupons that could have detected existing or potentialcorrosion were not regularly employed. In the view of the Safety Board, the preaccidentapproach of EPNG in regard to internal corrosion indicates that the company did notbelieve internal corrosion to be a significant issue in the safety of its pipeline operations.As a result, the company was inadequately attentive to the potential for severe internalcorrosion to occur, with the result that the corrosion that led to the rupture of line 1103 wasnot detected and mitigated in time to prevent a serious accident. The Safety Boardtherefore concludes that, before the accident, EPNG did not have in place an internalcorrosion control program that was adequate to identify or mitigate the internal corrosionthat was occurring in its pipelines.

After the acquisition of Sonat in January 2000, which had been preceded by theacquisition of Tenneco Energy in December 1996, El Paso Energy organized teams ofrepresentatives from each pipeline to determine best practices and produce a newoperating and maintenance manual. The resulting Operating and Maintenance Proceduresmanual was issued on May 15, 2000, followed by a Corrosion Control Manual on July 10,2000. These procedures were applicable to El Paso Energy�s gas pipeline companies andwere the approved procedures at the time of the accident in August 2000.

For Tenneco Energy, the internal corrosion procedures in use at the time of theDecember 1996 acquisition by EPNG were in the company�s Operating and MaintenanceManual. The procedure for internal corrosion detection and control was dated December1, 1993, and included a requirement to test gas and liquids being transported to determineif they are corrosive. A Corrosion Control Manual dated February 1, 1997 supplementedthe internal corrosion control procedures in the Operating and Maintenance Manual withadditional, detailed internal corrosion control considerations and measures.

Even though EPNG had access to Tenneco�s procedures after the acquisition, ittook an additional 41 months, from December 1996 to May 2000, for El Paso Energy todevelop and issue internal corrosion control procedures applicable to EPNG that includedrequirements for testing pipeline gas and liquids to determine if they are corrosive. It wasan additional 2 months, from May 15 to July 10, 2000, before the supplemental, detailedinternal corrosion control procedures were issued describing what to test for, where to test,and how often to test.

The program being implemented at the time of the accident was based on EPNG�sCorrosion Control Manual, Section 700, dated July 10, 2000 (subsequently revisedJanuary 15, 2001, revised October 1, 2001, and redesignated Section 6 and revisedDecember 19, 2001). The program recognized that gas quality standards alone areinsufficient to determine whether a pipeline is transporting corrosive gas. Theseprocedures state that the first line of defense against internal corrosion is gas and liquid


quality standards but that whether a pipeline transports corrosive gas cannot bedetermined from the standards themselves. Also noted in the documents is that industryexperience has shown that water and other corrosives may enter the pipeline by accidentor by operational upsets or that it may slowly accumulate in low spots despite gas qualitymonitoring that shows adherence to quality standards. The procedures state that�identification of corrosive gas in a pipeline is achieved by analysis of operatingconditions, gas impurity content, monitoring data, mitigation schemes, and/or otherconsiderations� and that �an effective internal corrosion-monitoring program includessampling and analysis of liquid, gas, and solid materials.� After the accident, the SafetyBoard�s analysis of the liquids and solids from the pipeline determined that potentiallycorrosive constituents such as water, chlorides, and bacteria were present in the pipeline.The Safety Board concludes that had EPNG effectively monitored the quality of gasentering the pipeline and the operating conditions in pipeline 1103 and periodicallysampled and analyzed the liquids and solids that were removed from the line, it wouldlikely have determined that the potential existed for significant corrosion to occur withinthe pipeline.

Federal Safety Regulations

Federal regulations for gas pipelines include two sections that have requirementsfor an internal corrosion control program and one section that requires that the proceduresfor the program be included in the operator�s operating and maintenance manual. Theregulations do not define �corrosive gas� but do state that such gas may not be transportedby pipeline unless its effect on the pipeline has been investigated and steps have beentaken to minimize internal corrosion. For internal corrosion to occur, water must typicallybe present in the pipeline, along with corrosive contaminants such as chlorides, H2S, CO2,O2, or bacteria. The regulations do not specifically address microbiologically influencedcorrosion or the way that water and contaminants in the pipeline can combine tocontribute to the corrosion process. The regulations also do not specifically address theimportance of the following: minimizing liquids and liquid accumulation in the pipeline,removing liquids from the pipeline, maintaining drips, and the role of gas velocity incorrosion control.

Because the Federal regulations do not specifically address the above issues, theSafety Board concludes that the current Federal pipeline safety regulations do not provideadequate guidance to pipeline operators or enforcement personnel in mitigating pipelineinternal corrosion. The Safety Board therefore believes that RSPA should develop therequirements necessary to ensure that pipeline operators� internal corrosion controlprograms address the role of water and other contaminants in the corrosion process.

Federal Oversight of the Pipeline Operator

On May 15, 2000, EPNG issued revised operating and maintenance procedures forinternal corrosion control. For each of the six OPS safety inspections of EPNG conducted


between May 15 and September 25, 2000, compliance with the Federal regulations forinternal corrosion control was noted by the inspectors as �satisfactory.� After the accident,however, the OPS cited EPNG for a number of probable violations related to its internalcorrosion program. For example, in its June 20, 2001, notice of probable violation, theOPS stated that EPNG�s internal corrosion control program was not carried out by, orunder the direction of, a person qualified in pipeline corrosion control methods. But ineach of the six inspections between May 15 and September 25, 2000, OPS inspectors hadnoted that the company�s program was ��under the direction of a qualified person, withassociated records�.� In several cases, the inspector included on the form a briefdescription of the qualifications of EPNG�s principal coordinator of corrosion services. Atno time did the OPS inspection process, even under the system integrity inspection pilotprogram, indicate a personnel qualification issue with EPNG�s corrosion program.

The postaccident notice of probable violation also cited EPNG for not followingits own procedures and sound engineering practice by not performing corrosiveness testson the liquids and solids that were removed from lines 1103 and 1110 after piggingoperations. But at no time during the inspections conducted before September 2000 didthe OPS indicate that such testing of liquids and solids was required or that it was soundengineering practice.

In addition, the notice of probable violation stated that EPNG�s elevation profiledrawings for its pipelines in the area of the Pecos River were incomplete. Specifically, thenotice stated that the drawings did not show any elevation profile for line 1103 betweenblock valve No. 6 and the Pecos River compressor station. Therefore, according to theOPS, EPNG did not know the location of low points in the pipeline where liquids couldaccumulate and thus could not take certain corrosion control steps that could possiblyhave prevented the accident. However, during none of the six inspections between Mayand September 2000 did the OPS indicate that profile drawings of pipelines were requiredor that there were any other compliance or safety issues with the pipeline maps.

Further, in April 2000, the OPS conducted a team review of EPNG�s operating andmaintenance procedures as part of the system integrity inspection pilot program. Nodeficiencies in the procedures were identified in this inspection, and the OPS did notrequire any follow-up actions by EPNG to correct compliance and safety problems. Butonly four questions related to an internal corrosion control program (coupon monitoringand records and corrosion remedial measures and records) were included on the inspectionform. The inspection form did not inquire into the four components of an effective internalcorrosion control program identified in the regulations (determining whether corrosive gasis being transported, inspection of pipe removed from a pipeline, qualification of internalcorrosion control personnel, and qualification of the person directing the internalcorrosion control program). Thus, because its inspections did not seek information fromthe operator in these four areas, the OPS did not have sufficient basis for evaluatingEPNG�s compliance with the Federal regulations for internal corrosion control.

Throughout the inspections conducted by the OPS to qualify EPNG for the systemintegrity inspection pilot program, OPS inspection reports documented that EPNG�sinternal audit program was working as designed. However, the procedures and forms used


by EPNG for its internal audits only addressed actions to be taken after it had beendetermined that corrosive gas was being transported. Not addressed in either the EPNGprocedures or forms reviewed by the OPS was how to determine if corrosive gas wasbeing transported. Thus, although the program was functioning, the internal audit programwas not adequate to uncover potential deficiencies in the company�s internal corrosioncontrol program.

Federal inspections of a pipeline operator should provide the operator withaccurate feedback and the opportunity for immediate, constructive dialog with the OPS. Inaddition, the OPS uses data obtained during field inspections to assess the effectiveness ofits regulations and identify issues of operator noncompliance. But in this case, the OPSpostaccident investigation documented deficiencies in EPNG operations that it had notpreviously identified. Had the preaccident inspections applied the enforcement criteria inthe same manner as they were interpreted after the accident, EPNG may have beenprompted to correct deficiencies in its programs. The Safety Board concludes that the OPSdid not make accurate preaccident assessments of EPNG�s internal corrosion program andtherefore did not identify deficiencies in the program before the accident. The SafetyBoard therefore believes that RSPA should evaluate the OPS�s pipeline operatorinspection program to identify deficiencies that resulted in the failure of inspectors, beforethe Carlsbad, New Mexico, accident, to identify the inadequacies in EPNG�s internalcorrosion control program. The Safety Board further believes that RSPA shouldimplement the changes necessary to ensure adequate assessments of pipeline operatorsafety programs.

Industry Standards

As shown by this accident, pipeline failure due to internal corrosion can haveserious consequences and, in the view of the Safety Board, industry standards andrecommended practices such as NACE RP0175-75, �Control of Internal Corrosion InSteel Pipelines and Piping Systems,� can be of significant benefit to pipeline operators.The Safety Board is concerned that, because RP0175-75 is not considered current and maycontain outdated information, pipeline operators may not have easy access to informationthat could contribute significantly to the establishment of an effective internal corrosioncontrol program. Even though the Safety Board has been told by NACE representativesthat the society is working on a new standard to replace RP0175-75, no timetable has beengiven for the completion of this effort. The Safety Board believes that NACE Internationalshould establish an accelerated schedule for completion of an industry standard for thecontrol of internal corrosion in steel pipelines that will replace or update NACE standardRP0175-75.


Conclusions

Findings

1. The following were neither causal nor contributory to the accident or its aftermath:overpressure of the pipeline, the interruption in or loss of supervisory control and dataacquisition system communication, external damage to the pipeline throughexcavation or other activities, and external corrosion of the pipeline.

2. Line 1103 ruptured as a result of severe internal corrosion that caused a reduction inpipe wall thickness to the point that the remaining metal could no longer contain thepressure within the pipe.

3. The corrosion that was found in line 1103 at the rupture site was likely caused by acombination within the pipeline of microbes and such contaminants as moisture,chlorides, oxygen, carbon dioxide, and hydrogen sulfide.

4. If the accident section of pipeline 1103 had been able to accommodate cleaning pigs,and if cleaning pigs had been used regularly with the resulting liquids and solidsthoroughly removed from the pipeline after each pig run, the internal corrosion thatdeveloped in this section of pipe would likely have been less severe.

5. As a likely result of the partial clogging of the �drip� upstream of the rupture location,some liquids bypassed the drip, continued through the pipeline, and accumulated andcaused corrosion at the eventual rupture site where pipe bending had created a lowpoint in the pipeline.

6. Had El Paso Natural Gas Company effectively monitored the quality of gas enteringthe pipeline and the operating conditions in pipeline 1103 and periodically sampledand analyzed the liquids and solids that were removed from the line, it would likelyhave determined that the potential existed for significant corrosion to occur within thepipeline.

7. Before the accident, El Paso Natural Gas Company did not have in place an internalcorrosion control program that was adequate to identify or mitigate the internalcorrosion that was occurring in its pipelines.

8. The current Federal pipeline safety regulations do not provide adequate guidance topipeline operators or enforcement personnel in mitigating pipeline internal corrosion.

9. The Office of Pipeline Safety did not make accurate preaccident assessments of ElPaso Natural Gas Company�s internal corrosion control program and therefore did notidentify deficiencies in the program before the accident.

Conclusions 50 Pipeline Accident Report

Probable Cause

The National Transportation Safety Board determines that the probable cause ofthe August 19, 2000, natural gas pipeline rupture and subsequent fire near Carlsbad, NewMexico, was a significant reduction in pipe wall thickness due to severe internalcorrosion. The severe corrosion had occurred because El Paso Natural Gas Company�scorrosion control program failed to prevent, detect, or control internal corrosion within thecompany�s pipeline. Contributing to the accident were ineffective Federal preaccidentinspections of El Paso Natural Gas Company that did not identify deficiencies in thecompany�s internal corrosion control program.


Recommendations

As a result of its investigation of the August 19, 2000, pipeline rupture andsubsequent fire near Carlsbad, New Mexico, the National Transportation Safety Boardmakes the following safety recommendations:

To the Research and Special Programs Administration:

Revise 49 Code of Federal Regulations Part 192 to require that new orreplaced pipelines be designed and constructed with features to mitigateinternal corrosion. At a minimum, such pipelines should (1) be configuredto reduce the opportunity for liquids to accumulate, (2) be equipped witheffective liquid removal features, and (3) be able to accommodatecorrosion monitoring devices at locations with the greatest potential forinternal corrosion. (P-03-1)

Develop the requirements necessary to ensure that pipeline operators�internal corrosion control programs address the role of water and othercontaminants in the corrosion process. (P-03-2)

Evaluate the Office of Pipeline Safety�s pipeline operator inspectionprogram to identify deficiencies that resulted in the failure of inspectors,before the Carlsbad, New Mexico, accident, to identify the inadequacies inEl Paso Natural Gas Company�s internal corrosion control program.Implement the changes necessary to ensure adequate assessments ofpipeline operator safety programs. (P-03-3)

To NACE International:

Establish an accelerated schedule for completion of an industry standardfor the control of internal corrosion in steel pipelines that will replace orupdate NACE standard RP0175-75. (P-03-4)

BY THE NATIONAL TRANSPORTATION SAFETY BOARD

JOHN A. HAMMERSCHMIDT JOHN J. GOGLIAActing Chairman Member

CAROL J. CARMODYMember

Adopted: February 11, 2003


Appendix A

Investigation

The National Transportation Safety Board was notified on August 19, 2000,through the National Response Center, of a pipeline explosion and fire south of Carlsbad,New Mexico. The Safety Board dispatched an investigative team from its Washington,D.C., headquarters. The team comprised investigative groups in pipeline operations,corrosion, survival factors, and family assistance. Board Members John Hammerschmidtand Carol Carmody accompanied the investigative team. Then-Chairman Jim Hall wasalso at the accident site during the on-scene portion of the investigation. No hearings ordepositions were held in conjunction with the investigation. Representatives from El PasoNatural Gas Company and the Office of Pipeline Safety participated in the investigation.


Appendix B

Summary of Office of Pipeline Safety Corrective Action Order

On August 23, 2000, the Office of Pipeline Safety issued a corrective action orderrequiring EPNG to take the necessary corrective actions to protect the public andenvironment from potential hazards associated with its pipeline operations.

The corrective action order listed 25 required corrective action items, summarizedas follows:

Line 1110 between block valve No. 6 and the Pecos River compressor station:

� Utilizing x-ray and ultrasonic examination techniques, assess the integrity ofthe pipeline at all locations that may have a no-flow condition or where liquidsmay accumulate, and implement corrective actions;

� Hydrostatically test the pipeline to at least 90 percent SMYS;

� Prepare status reports and summary of findings and submit to RSPA;

� After return to service plan is approved by RSPA, restrict the operatingpressure to 538 psig (80 percent of actual pressure at the time of the failure);maintain pressure restriction until released by OPS.

Line 1103 between block valve No. 6 and the Pecos River compressor station:

� Remain out of service until additional information about the rupture isreviewed.

Line 1100 between station 2482+52 (6.1 miles upstream of block valve No. 6) andthe Pecos River compressor station:

� Utilizing x-ray and ultrasonic examination techniques, assess the integrity ofthe pipeline at all locations that may have a no-flow condition or where liquidsmay accumulate, and implement corrective actions;

� Obtain OPS approval for the design of the temporary crossing of the PecosRiver;

� Hydrostatically test the pipeline to at least 90 percent SMYS;

� Prepare status reports and summary of findings and submit to RSPA;

� After return to service plan is approved by RSPA, restrict the operatingpressure to 538 psig (80 percent of actual pressure at the time of the failure);maintain pressure restriction until released by OPS.

Appendix B 55 Pipeline Accident Report

Lines 1103 and 1110 between Keystone Compressor Station and GuadalupeCompressor Station, and Line 1100 between Eunice plant and GaudalupeCompressor Station:

� Restrict operating pressure to 668 psig (80 percent of MAOP) until released byRSPA;

� Develop a risk-based plan to inspect for indications of internal corrosion andassess and correct (1) areas in the pipeline that cannot be inspected with aninternal inspection tool, (2) areas that may have a no-flow condition, and (3)areas where liquids may accumulate;

� Provide RSPA with an analysis of the continued safe operation of lines 1100,1103, and 1110.

All pipelines operated by EPNG:

� Obtain OPS approval of corrective action plans, which must describe thecriteria for evaluating corroded areas and the criteria used to select thecorrective action;

� Complete the submission of EPNG�s pipeline system information to theNational Pipeline Mapping System;

� Obtain OPS approval for design of the permanent crossings of the Pecos River;

� Develop a risk-based plan to inspect for indications of internal corrosion andassess and correct (1) areas in the pipeline that cannot be inspected with aninternal inspection tool, (2) areas that may have a no-flow condition, and (3)areas where liquids may accumulate.


Appendix C

Research and Special Programs Administration Advisory Bulletin

On August 29, 2000, the Research and Special Programs Administration issuedAdvisory Bulletin ADB-00-02 to all operators of natural gas transmission pipelines:

DEPARTMENT OF TRANSPORTATION

Research and Special Programs Administration

1. Pipeline Safety: Internal Corrosion in Gas Transmission Pipelines

AGENCY: Research and Special Programs Administration (RSPA), DOT

ACTION: Notice; issuance of advisory bulletin.

SUMMARY: The Office of Pipeline Safety (OPS) is issuing this bulletin to ownersand operators of natural gas transmission pipeline systems to advise them to review theirinternal corrosion programs. Operators should consider factors that influence theformation of internal corrosion, including gas quality and operating parameters. Operatorsshould give special attention to pipeline alignment features that may contribute to internalcorrosion by allowing condensates to settle out of the gas stream. This action follows areview of incidents involving internal corrosion, some of which resulted in loss of life,injuries, and significant property damage. OPS� preliminary investigation of a recent gastransmission pipeline incident found wall thinning on damaged pipe associated with theincident. The wall thinning is consistent with that caused by internal corrosion.

SUPPLEMENTARY INFORMATION:

I. Background

Internal corrosion control in gas transmission pipelines is addressed in the Federalpipeline safety regulations at 49 CFR 192.475 and 192.477. Internal corrosion is mostoften found in gas transmission pipelines and appurtenances in the vicinity of productionand gathering facilities or storage fields.

An OPS review of incident reports and inspections indicated that better industryguidance is needed to determine the best practices for monitoring the potential for internalcorrosion in gas transmission pipelines. Some methods for monitoring internal corrosionare weight loss coupons, radiography, water chemistry tests, in-line inspection tools, andelectrical, galvanic, resistance, and hydrogen probes. Operators should refer to availablerecommended practices provided by national consensus standards organizations, such asthe American Petroleum Institute, the National Association of Corrosion Engineers, and

Appendix C 57 Pipeline Accident Report

the Gas Piping Technology Committee (GPTC) for guidance in addressing internalcorrosion issues.

OPS has worked with GPTC to revise the Guide for Gas Transmission andDistribution Piping Systems (Guide) to better address the control of internal corrosion.GPTC is considering modifying the Guide to address design considerations, correctivemeasures and detection techniques for internal corrosion.

II. Advisory Bulletin August 29, 2000

To: Owners and Operators of Gas Transmission Pipelines.

Subject: Internal Corrosion in Gas Transmission Pipelines.

Purpose: To advise owners and operators of natural gas transmission pipelines ofthe need to review their internal corrosion monitoring programs and operations.

Advisory: Owners and operators of natural gas transmission pipelines shouldreview their internal corrosion monitoring programs and consider factors that influencethe formation of internal corrosion, including gas quality and operating parameters.Operators should give special attention to pipeline alignment features that may contributeto internal corrosion by allowing condensates to settle out of the gas stream. This actionfollows a review of incidents involving internal corrosion, some of which resulted in lossof life, injuries, and significant property damage. OPS� preliminary investigation of arecent gas transmission pipeline incident found internal wall thinning on damaged pipeassociated with the incident. The wall thinning is consistent with that caused by internalcorrosion.

Gas transmission owners and operators should thoroughly review their internalcorrosion management programs and operations:

Review procedures for testing to determine the existence or severity of internalcorrosion associated with their pipelines. Some methods for monitoring internal corrosionare weight loss coupons, radiography, water chemistry tests, in-line inspection tools, andelectrical, galvanic, resistance and hydrogen probes.

Special attention should be given to specific conditions, including flowcharacteristics, pipeline location (especially drips, deadlegs, and sags, which are on-linesegments that are not cleaned by pigging or other methods, fittings and/or �stabbed�connections which could affect gas flow), operating temperature and pressure, watercontent, carbon dioxide and hydrogen sulfide content, carbon dioxide partial pressure,presence of oxygen and/or bacteria, and sediment deposits.

Review conditions in pipeline segments downstream of gas production and storagefields.

Review conditions in pipeline segments with low spots, sharp bends, suddendiameter changes, and fittings that restrict flow or velocity. These features can contribute tothe formation of internal corrosion by allowing condensates to settle out of the gas stream.

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